[Federal Register Volume 77, Number 135 (Friday, July 13, 2012)]
[Rules and Regulations]
[Pages 41481-41546]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-15762]
[[Page 41481]]
Vol. 77
Friday,
No. 135
July 13, 2012
Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Integration of Variable Energy Resources; Final Rule
Federal Register / Vol. 77 , No. 135 / Friday, July 13, 2012 / Rules
and Regulations
[[Page 41482]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM10-11-000; Order No. 764]
Integration of Variable Energy Resources
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission is amending the pro
forma Open Access Transmission Tariff to remove unduly discriminatory
practices and to ensure just and reasonable rates for Commission-
jurisdictional services. Specifically, this Final Rule removes barriers
to the integration of variable energy resources by requiring each
public utility transmission provider to: offer intra-hourly
transmission scheduling; and, incorporate provisions into the pro forma
Large Generator Interconnection Agreement requiring interconnection
customers whose generating facilities are variable energy resources to
provide meteorological and forced outage data to the public utility
transmission provider for the purpose of power production forecasting.
DATES: Effective Date: This rule will become effective September 11,
2012.
FOR FURTHER INFORMATION CONTACT:
Jessica L. Cockrell (Technical Information), Office of Energy Policy
and Innovation, Federal Energy Regulatory Commission, 888 First Street
NE., Washington, DC 20426, (202) 502-8190.
Andrea Hilliard (Legal Information), Office of General Counsel--Energy
Markets, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-8288.
SUPPLEMENTARY INFORMATION:
139 FERC ] 61,246
Department of Energy
Federal Energy Regulatory Commission
Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, Cheryl A. LaFleur, and Tony T. Clark.
Issued June 22, 2012.
Table of Contents
I. Introduction............................................. 1
Background.............................................. 6
II. The Need for Reform..................................... 11
A. Commission Proposal.................................. 11
B. Comments............................................. 12
C. Commission Determination............................. 16
III. Legal Authority To Implement Proposed Reforms.......... 25
A. Commission Proposal.................................. 25
B. Comments............................................. 26
C. Commission Determination............................. 36
IV. Proposed Reforms........................................ 51
A. Intra-Hour Scheduling................................ 51
1. Intra-Hour Scheduling Requirement................ 52
2. Implementation of Intra-Hour Scheduling.......... 114
3. Other Issues..................................... 148
B. Data Reporting To Support Power Production 154
Forecasting............................................
1. Data Requirements................................ 155
2. Definition of VER................................ 200
3. Data Sharing..................................... 217
4. Cost Recovery.................................... 222
C. Generator Regulation Service-Capacity................ 233
1. Schedule 10-Generator Regulation and Frequency 234
Response Service...................................
2. Mechanics of a Generator Regulation Charge....... 276
3. Use of Contingency Reserves...................... 336
V. Other Issues............................................. 343
1. Regulatory Text...................................... 343
2. Market Mechanisms.................................... 346
3. Power Factor Design.................................. 363
VI. Compliance.............................................. 365
VII. Information Collection Statement....................... 378
VIII. Environmental Analysis................................ 383
IX. Regulatory Flexibility Act Analysis..................... 384
X. Document Availability.................................... 385
XI. Effective Date and Congressional Notification........... 388
I. Introduction
1. In this Final Rule, the Commission acts under section 206 of the
Federal Power Act (FPA) to adopt reforms that will remove barriers to
the integration of variable energy resources (VER) \1\ and ensure that
the rates, terms, and conditions for Commission-jurisdictional services
provided by public utility transmission providers are just and
reasonable and not unduly discriminatory or preferential.\2\ As the
Commission noted in the Proposed Rule (75 FR 75336, December 2, 2010),
VERs are making up an increasing percentage of new generating capacity
being brought on-line.\3\ This evolution in the Nation's generation
fleet has caused the industry to reevaluate practices
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developed at a time when virtually all generation on the system could
be scheduled with relative precision and when only load exhibited
significant degrees of within-hour variation. As part of this
evaluation, the Commission initiated this rulemaking proceeding to
consider its own rules and, based on the comments received, concludes
that reforms are needed in order to ensure that transmission customers
are not exposed to excessive or unduly discriminatory charges and that
public utility transmission providers have the information needed to
efficiently manage reserve-related costs.
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\1\ As defined in the Notice of Proposed Rulemaking, a Variable
Energy Resource is a device for the production of electricity that
is characterized by an energy source that: (1) Is renewable; (2)
cannot be stored by the facility owner or operator; and (3) has
variability that is beyond the control of the facility owner or
operator. This includes, for example, wind, solar thermal and
photovoltaic, and hydrokinetic generating facilities. See
Integration of Variable Energy Resources Notice of Proposed
Rulemaking, FERC Stats. & Regs. ] 32,664, at P 64 (2010) (Proposed
Rule).
\2\ 16 U.S.C. 824e (2006).
\3\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 13.
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2. Specifically, the Commission amends the pro forma Open Access
Transmission Tariff (OATT) to provide all transmission customers the
option of using more frequent transmission scheduling intervals within
each operating hour, at 15-minute intervals. There is currently no
requirement to provide transmission customers the opportunity to adjust
their transmission schedules within the hour to reflect changes in
generation output. As a result, transmission customers have no ability
under the pro forma OATT to mitigate Schedule 9 generator imbalance
charges in situations when the transmission customer knows or believes
that generation output will change within the hour. This lack of
ability to update transmission schedules within the hour can cause
charges for Schedule 9 generator imbalance service to be unjust and
unreasonable or unduly discriminatory. Accordingly, the Commission
amends the pro forma OATT to correct this deficiency.
3. The Commission also amends the pro forma Large Generator
Interconnection Agreement (LGIA) to require new interconnection
customers whose generating facilities are VERs to provide
meteorological and forced outage data to the public utility
transmission provider with which the customer is interconnected, where
necessary for that public utility transmission provider to develop and
deploy power production forecasting. Power production forecasts can
provide public utility transmission providers with advanced knowledge
of system conditions needed to manage the variability of VER generation
through the unit commitment and dispatch process, rather than through
the deployment of reserve service, such as regulation reserves which
can be more costly. This Final Rule facilitates a public utility
transmission provider's use of power production forecasting by amending
the pro forma LGIA to require new interconnection customers whose
generating facilities are VERs to provide the underlying data necessary
for public utility transmission providers to perform such forecasts
accurately.
4. The Commission declines, however, to modify the pro forma OATT
to include a new Schedule 10 governing generator regulation service as
set forth in the Proposed Rule. The Commission intended for the
proposed Schedule 10 to provide clarity to public utility transmission
providers and transmission customers alike by setting forth a generic
approach to the provision of generator regulation service. In response,
numerous commenters urged the Commission not to adopt a standardized
approach to generator regulation service, stressing that flexibility is
needed in the design of capacity services needed to efficiently
integrate VERs into the transmission system. The Commission agrees and,
accordingly, will continue a case-by-case approach to evaluating
proposed generator regulation service charges. To assist public utility
transmission providers and their customers in the development and
evaluation of such proposals, the Commission instead provides guidance
in response to the comments submitted.
5. Taken together, the reforms adopted and guidance provided in
this Final Rule are intended to address issues confronting public
utility transmission providers and VERs and to allow for the more
efficient utilization of transmission and generation resources to the
benefit of all customers. This, in turn, fulfills our statutory
obligation to ensure that Commission-jurisdictional services are
provided at rates, terms, and conditions of service that are just and
reasonable and not unduly discriminatory or preferential.
Background
6. In 1996, the Commission issued Order No. 888, which found that
it was in the economic interest of public utility transmission
providers to deny transmission service or to offer transmission service
on a basis that is inferior to what they provide to themselves.\4\
Concluding that unduly discriminatory and anticompetitive practices
existed in the electric industry and that, absent Commission action,
such practices would increase as competitive pressures in the industry
grew, the Commission in Order No. 888 required all public utility
transmission providers that own, control, or operate transmission
facilities used in interstate commerce to have on file an open access,
non-discriminatory transmission tariff that contains minimum terms and
conditions of non-discriminatory service. As relevant here, the pro
forma OATT contains terms for scheduling transmission service and the
provision of ancillary services.
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\4\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,682 (1996), order
on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
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7. The Commission later turned its attention to the process by
which large generators interconnect with the interstate transmission
system. In Order No. 2003, the Commission concluded that there was a
pressing need for a single set of procedures and a single, uniformly
applicable interconnection agreement for large generator
interconnections.\5\ Accordingly, the Commission adopted standard
procedures (the Large Generator Interconnection Procedures or LGIP) and
a standard agreement (the LGIA) for the interconnection of generation
resources greater than 20 MW.\6\ These reforms were designed to
minimize opportunities for undue discrimination and to expedite the
development of new generation, while protecting reliability and
ensuring that rates are just and reasonable.\7\
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\5\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 11
(2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ]
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs.
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
\6\ See Order No. 2003, FERC Stats. & Regs. ] 31,146.
\7\ Id.
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8. In Order No. 2003-A, the Commission explained that the
interconnection requirements adopted in Order No. 2003 were based on
the needs of traditional synchronous generators and that a different
approach may be appropriate for generators relying on newer
technology.\8\ Therefore, Commission exempted wind resources from
certain sections of the LGIA and added Appendix G to the LGIA, as a
placeholder for the inclusion of interconnection standards specific to
newer technologies.\9\ Subsequently, in Orders Nos. 661 and 661-A, the
Commission adopted a package of interconnection standards applicable to
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large wind generators for inclusion in Appendix G of the LGIA.\10\
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\8\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 407 &
n.85.
\9\ Id.
\10\ Interconnection for Wind Energy, Order No. 661, FERC Stats.
& Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. &
Regs. ] 31,198 (2005).
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9. In recognition of the evolving energy industry and in a further
effort to remedy the potential for undue discrimination, the Commission
returned to the pro forma OATT in Order No. 890 and implemented a
series of changes to the requirements of open access transmission
service.\11\ Among other things, the Commission adopted a set of
transmission planning principles,\12\ created a new pro forma ancillary
service schedule designed to address generator imbalances,\13\ and
instituted a new conditional firm transmission product.\14\ With regard
to imbalance charges, the Commission found that such charges should be
designed to provide appropriate incentives to keep schedules accurate
without being excessive and otherwise result in consistency in charges
between and among energy and generator imbalances.\15\ The Commission
recognized that intermittent resources, such as VERs, cannot always
accurately follow their schedules and that high penalties for
imbalances will not lessen the incentive to deviate from their
schedules. Accordingly, the Commission exempted intermittent resources
from third-tier deviation band of imbalance penalties.\16\
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\11\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008),
order on reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009), order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
\12\ Order No. 890, FERC Stats. & Regs. ] 31,241 at PP 444-561.
In June 2011, the Commission further amended the pro forma OATT to
require, among other things, that each public utility transmission
provider participate in a regional transmission planning process
that produces a regional transmission plan and has a regional cost
allocation method for the cost of new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation. Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public Utilities, Order No. 1000,
176 FR 49842 (Aug. 11 2011), FERC Stats. & Regs. ] 31,323 (2011).
\13\ Order No. 890, FERC Stats. & Regs. ] 31,241 at PP 663-72.
\14\ Id. PP 911-15.
\15\ Id. P 72.
\16\ Id. P 665.
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10. Against this backdrop, the Commission in January 2010 issued a
Notice of Inquiry in this proceeding to explore the extent to which
barriers may exist that impede the reliable and efficient integration
of VERs into the electric grid and whether reforms are needed to
eliminate those barriers.\17\ The Commission noted that the amount of
VERs is rapidly increasing, reaching a point where such resources are
becoming a significant component of the nation's energy supply
portfolio.\18\ In order to determine whether any rules, regulations,
tariffs or industry practices within the Commission's jurisdiction
hinder the reliable and efficient integration of VERs, the Commission
sought comment on a range of subject areas: (1) Power production
forecasting, including specific forecasting tools and data and
reporting requirements; (2) scheduling practices, flexibility, and
incentives for accurate scheduling of VERs; (3) forward market
structure and reliability commitment processes; (4) balancing authority
area coordination and/or consolidation; (5) suitability of reserve
products and reforms necessary to encourage the efficient use of
reserve products; (6) capacity market reforms; and (7) redispatch and
curtailment practices necessary to accommodate VERs in real time.\19\
The response from commenters was significant, with more than 135
entities submitting comments, many of which urged the Commission to
undertake basic reforms in response to the increasing number of VERs
being integrated into the system.
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\17\ Integration of Variable Energy Resources Notice of Inquiry,
FERC Stats. & Regs. ] 35,563 (2010) (Notice of Inquiry).
\18\ Id. P 2.
\19\ Id. P 12.
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II. The Need for Reform
A. Commission Proposal
11. In light of the changes occurring within the electric industry,
and based on comments submitted in response to the January 2010 Notice
of Inquiry, the Commission issued the Proposed Rule to remedy
operational and other challenges associated with VER integration that
may be causing undue discrimination and increased costs ultimately
borne by consumers. The Commission preliminarily found that the
proposed set of reforms would eliminate operational procedures that
have the de facto effect of imposing an undue burden on VERs. The
Commission stated that the proposed reforms acknowledge that existing
practices as well as the ancillary services used to manage system
variability were developed at a time when virtually all generation on
the system could be scheduled with relative precision and when only
load exhibited significant degrees of within-hour variation. In
proposing its reforms, the Commission sought to ensure that VERs are
integrated into the transmission system in a coherent and cost-
effective manner, consistent with open access principles.\20\
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\20\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 17.
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B. Comments
12. Commenters largely support initiation of a rulemaking
proceeding to consider potential reforms to reduce discrimination and
improve the efficiency of the transmission system.\21\ Invenergy Wind,
for example, states that the Proposed Rule reflects an important step
forward in providing the regulatory foundation that will create an
incentive for improvements in system operations and procurement
practices necessary to support the addition of renewable resources to
the nation's historical generation mix. BP Companies comment that it is
important for the Commission to provide a level playing field for wind
and solar-generated power.
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\21\ E.g., ACSF; AEP; AWEA; Argonne National Lab; BP Companies;
Business Council; California ISO; CMUA; CEERT; Center for Rural
Affairs; Clean Line; CGC; Defenders of Wildlife; Dominion; EEI;
Environmental Defense Fund; Exelon; First Wind; Iberdrola; Idaho
Power; ITC Companies; ISO New England; Independent Power Producers
Coalition--West; ISO/RTO Council; Invenergy Wind; Large Public Power
Council; Massachusetts DPU; MidAmerican; Midwest ISO Transmission
Owners; M-S-R Public Power Agency; National Grid; NaturEner; Oregon
& New Mexico PUC; NextEra; NorthWestern; PNW Parties; PJM; Powerex;
Public Interest Organizations; RenewElec; SMUD; San Diego Gas &
Electric; SEIA; Southern California Edison; SWEA; Southwestern;
Sunflower and Mid-Kansas; Tacoma Power; Vestas; Western Farmers;
Western Grid; Xcel.
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13. Many commenters point to the importance of the Proposed Rule in
removing market barriers to VER integration. NextEra comments that the
instant proceeding is important because VERs have been developed in
relatively modest amounts until recent years, and the existing market
rules were designed to reflect the characteristics of more traditional
generating resources (e.g., coal, natural gas and nuclear generation)
rather than VERs. NextEra contends that existing rules were aimed at
addressing the preferences and requirements of the resources and
systems in the past, rather than to anticipate future changes. CEERT
states that the Commission's initiative to remove market and
operational barriers to VERs integration and eliminate undue
discrimination against VERs is critical to making wholesale power
markets more competitive and ensuring a sustainable energy future.
14. Iberdrola contends that this proceeding is the best opportunity
available for the federal government to encourage the responsible
development of renewable energy resources, and to avoid inadvertently
stifling the growth
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of renewable energy resources in an effort to protect the economic
interests of incumbents. Similarly, NaturEner comments that the reforms
are long overdue and should be implemented without further delay and in
a manner requiring prompt compliance. This proceeding, NaturEner
states, represents substantial progress towards the elimination of
antiquated rules, requirements and processes, a significant reduction
in duplication, unnecessary expenditures and inefficient allocation of
resources, as well as an important step towards making the grid more
robust, economical, and equitable.
15. Oregon & New Mexico PUC state that the Commission can play a
valuable role in enabling the western electricity industry to reach
state renewable energy goals at a reasonable cost to consumers by
exercising its jurisdiction in these areas. Oregon & New Mexico PUC
submit that the proposals in the Proposed Rule are an important step
toward building the necessary foundation to integrate significant
amounts of wind and solar in the West. Defenders of Wildlife similarly
contend that by establishing a new rule which encourages VER
integration, and long-term and much needed infrastructure investments
can be made today to help spur the nation's growing renewable energy
economy. ACSF states its strong support for Commission action to
integrate VERs into a smarter, cleaner, and more flexible energy grid,
whose principal design features should enable much more widespread
investment and deployment of integrated and hybrid VER generation
systems. ACSF states it is critical that the Commission exercise its
authority to develop policies that send adequate economic signals that
permit the country's most flexible, clean generation sources to provide
complementary power for VERs.
C. Commission Determination
16. As noted above, the Commission initiated this proceeding
through the issuance of a Notice of Inquiry to obtain information on
barriers to the integration of VERs. The Commission sought to
understand the challenges associated with the large-scale integration
of VERs on the interstate transmission system and the extent to which
existing operational practices may be imposing barriers to their
integration. The Commission explained that the changing characteristics
of the nation's generation portfolio compelled a fresh look at existing
policies and practices, leading the Commission to seek comment on a
range of issues.
17. Based on its review of comments to the Notice of Inquiry, the
Commission focused in the Proposed Rule on a series of basic reforms
regarding transmission scheduling, data reporting requirements, and
charges for generator regulation service that can and should be
implemented in the near term.\22\ The Commission explained that, taken
together, the Proposed Reforms were designed to address issues
confronting public utility transmission providers and VERs and to allow
for the more efficient utilization of transmission and generation
resources to the benefit of all customers.\23\ The Commission
acknowledged that the proposed reforms focused on discrete operational
protocols that were only a subset of the issues for which comment was
sought in the Notice of Inquiry.\24\ The Commission stated its belief
that focusing on the particular set of reforms proposed would provide a
reasonable foundation for public utility transmission providers seeking
to manage system variability associated with increased numbers of VERs
and that further study is required for many of the remaining issues
raised in the Notice of Inquiry.\25\
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\22\ Proposed Rule, FERC Stats. & Regs ] 32,664 at P 18.
\23\ Id. P 19.
\24\ Id. PP 23-24.
\25\ Id. PP 12, 24.
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18. The Commission received more than 1900 pages of initial and
reply comments in response to the Proposed Rule. While differing in
opinion on the merits of particular aspects of the Commission's
proposal, commenters generally support the Commission's efforts to
evaluate its rules through this rulemaking to explore further
opportunities to reduce undue discrimination and reduce costs
ultimately borne by consumers through more efficient use of the
transmission system. Based on these comments, the Commission concludes
that it is appropriate to act at this time to revise the transmission
scheduling requirements of the pro forma OATT and incorporate data
reporting requirements into the pro forma LGIA, as discussed in further
detail later in this Final Rule.\26\ As discussed throughout this Final
Rule, these reforms are necessary to ensure that transmission customers
are not exposed to excessive or unduly discriminatory charges for
Schedule 9 generator imbalance service and to provide public utility
transmission providers with information necessary to more efficiently
manage reserve-related costs recovered from transmission customers
through other ancillary services charges.
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\26\ For the reasons discussed in Schedule 10 below, the
Commission declines to standardize charges for generator regulation
service through the adoption of a generic Schedule 10 to the pro
forma OATT as suggested in the Proposed Rule.
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19. The Commission takes this action now recognizing that the
composition of the electric generation portfolio continues to change.
VERs are making up an increasing percentage of new generating capacity
being brought on-line. New wind generating capacity accounted for 35
percent of all newly installed generating capacity from 2007-2010.\27\
As of December 2011, nearly 12,000 MW of additional wind generating
capacity has been brought online and another 8,320 MW of wind
generating capacity is currently under construction.\28\ Current
projections indicate that this expansion will continue, with the Energy
Information Agency forecasting that generation from wind power will
nearly double between 2009 and 2035.\29\ This recent and future growth
is being facilitated by developments in state and federal public
policies that encourage the expansion of VER generation.\30\
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\27\ See American Wind Energy Association, Wind Power Outlook
2011 (Apr. 2011), available at http://www.awea.org/_cs_upload/learnabout/publications/reports/8546_1.pdf.
\28\ American Wind Energy Association, U.S. Wind Industry Fourth
Quarter 2011 Market Report (Jan. 2012), available at http://www.awea.org/learnabout/industry_stats/upload/4Q-2011-AWEA-Public-Market-Report_1-31.pdf. In addition, the amount of new photovoltaic
generating capacity in 2011 increased by 108 percent over 2010
amounts, adding 1,855 MW of PV and bringing the total solar
generating capacity to more than 4,470 MW. Utility installations
increased by 185 percent in 2011, far more than residential or
commercial market segments. See Solar Energy Industries Ass'n, US
Solar Market Insight Report 2011 Year-in-Review Executive Summary
(Mar. 2012), available at http://www.seia.org/galleries/pdf/SMI-YIR-2011-ES.pdf.
\29\ Annual Energy Outlook at 75, available at http://www.eia.gov/forecasts/archive/aeo11/pdf/0383(2011).pdf.
\30\ For example, as of May 2011, 30 states and the District of
Columbia have a renewable portfolio standard or goal. FERC, Div. of
Energy Market Oversight, Renewable Power and Energy Efficiency
Market: Renewable Portfolio Standards 1 (updated May 2011),
available at http://www.ferc.gov/market-oversight/othr-mkts/renew/othr-rnw-rps.pdf). In addition, the federal production tax credit,
which has been in effect intermittently since the early 1990s,
provides an inflation-adjusted credit for power produced from VERs
and other renewable resources. 26 U.S.C. 45 (2007). In February
2009, the American Recovery and Reinvestment Act not only extended
the production tax credit for a period of three additional years but
also instituted an investment tax credit, which allows developers of
certain renewable generation facilities to take a 30 percent cash
grant in lieu of the production tax credit. American Recovery and
Reinvestment Tax Act of 2009, Pub. L. 111-5, Sec. 1101, 123 Stat.
115, 319-20 (2009). Other federal policies that provide incentives
to renewable generation facilities include accelerated depreciation
of certain renewable generation facilities and loan guarantee
programs.
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20. As NERC has noted, higher levels of variable generation can
alter the operation and characteristics of the bulk power system.\31\
Increasing the relative amount of variable generation on a system can
increase operational uncertainty that the system operator must manage
through operating criteria, practices and procedures, including the
commitment of adequate reserves.\32\ However, many of these operational
protocols were developed for generation resources with a different set
of characteristics. For example, the hourly scheduling protocols of the
pro forma OATT reflect historical practices associated with operation
of conventional generating resources that are relatively predictable
and controllable when compared to VERs. Similarly, the interconnection
requirements of Order No. 2003 were based on the needs of traditional
synchronous generators, leading the Commission to revisit those
requirements as applied to large wind generators in Order Nos. 661 and
661-A.
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\31\ NERC, Accommodating High Levels of Variable Generation at
8, available at http://www.nerc.com/docs/pc/ivgtf/IVGTF_Report_041609.pdf.
\32\ Id. at 59.
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21. In Order No. 1000, the Commission recognized that changes in
the generation mix influence the need for new transmission facilities
and, as a result, Commission policies governing transmission planning
and cost allocation.\33\ The Commission concluded there that the
increased focus on investment in new transmission projects made it
critical to implement planning and cost allocation reforms to ensure
that the transmission projects that come to fruition efficiently and
cost-effectively meet regional needs. The Commission reaches a similar
conclusion here. Changes in the generation mix and underlying public
policies influencing investment in VER generation have accentuated the
need to reform existing practices that unduly discriminate against VERs
or otherwise impair the ability of public utility transmission
providers and their customers to manage costs associated with VER
integration effectively.
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\33\ Order No. 1000, 76 FR 49842, FERC Stats. & Regs. ] 31,323
at PP 45-46.
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22. Specifically, we find that the adoption of intra-hour
scheduling and data reporting to support power production forecasting
will remedy undue discrimination and ensure just and reasonable rates
through more efficient utilization of transmission and generation
resources.\34\ With regard to transmission scheduling practices,
existing hourly scheduling protocols can expose transmission customers
to excessive or unduly discriminatory generator imbalance charges.
Generator imbalance charges are assessed to pay for the energy service
the transmission provider must offer to account for deviations between
a transmission customer's scheduled delivery of energy from a generator
and the amount of energy actually generated, and also to provide an
appropriate incentive for transmission customers to maintain accurate
schedules. Under Schedule 9 of the pro forma OATT, there is no
requirement to provide customers the opportunity to adjust their
transmission schedules within the hour to reflect changes in generator
output. As a result, transmission customers have no ability under the
pro forma OATT to mitigate Schedule 9 generator imbalance charges in
situations where the customer knows or believes that generation output
will change within the hour. Implementation of intra-hour scheduling
under this Final Rule will provide VERs and other transmission
customers the flexibility to adjust their transmission schedules, thus
limiting their exposure to imbalance charges. Over time, implementation
of intra-hour scheduling also will allow public utility transmission
providers to rely more on planned scheduling and dispatch procedures,
and less on reserves, to maintain overall system balance.
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\34\ In the Proposed Rule, the Commission also proposed to
modify the pro forma OATT to include a new Schedule 10 governing
generator regulation service. For the reasons discussed elsewhere in
this Final Rule, the Commission declines to adopt that aspect of the
Proposed Rule, instead providing guidance in response to comments
submitted to assist public utility transmission providers and their
customers in the development and evaluation of proposals on a case-
by-case basis.
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23. With regard to data reporting to support power production
forecasting, the lack of data reporting requirements can limit the
ability of public utility transmission providers to develop and deploy
power production forecasts in an effort to more efficiently manage
operating costs associated with the integration of VERs interconnecting
to their systems. Under the existing requirements of the pro forma
LGIA, public utility transmission providers are permitted to request
this information, but there is no obligation for interconnection
customers whose generating facilities are VERs to provide it.
Implementation of reporting requirements commensurate with the power
production forecasting employed by the public utility transmission
provider will allow for more accurate commitment or de-commitment of
resources providing reserves, ensuring that reserve-related charges
imposed on customers remain just and reasonable and not unduly
discriminatory or preferential. While the Commission declines to adopt
a pro forma generator regulation and frequency response service, we
note that public utility transmission providers that decide to file
with the Commission to impose such a charge should, as part of any
filing, consider the affect of the reforms we adopt in this Final Rule
when developing proposed reserve capacity costs and evaluating whether
to require different transmission customers to purchase or otherwise
account for different quantities of generator regulation reserves.
24. Although focused on discrete issues, the implementation of
intra-hour scheduling and reporting requirements through this Final
Rule will allow for the efficient utilization of transmission and
generation resources as an increasing amount of VER generation is
integrated into the system. This in turn will ensure that the rates,
terms, and conditions for Commission-jurisdictional services provided
by public utility transmission providers are just and reasonable and
not unduly discriminatory. Our actions here are intended to build on,
rather than undermine, existing efforts at the regional level to
address VER integration. The Commission acknowledges that significant
work has been done through industry initiatives seeking to craft
regional solutions to the challenges associated with VER integration.
For example, many public utility transmission providers in the Western
Interconnection have implemented some form of transmission scheduling
at 30-minute intervals.\35\ The Commission is acting here to implement
a minimum set of requirements for all public utility transmission
providers and new interconnection customers whose generating facilities
are VERs as necessary to facilitate the efficient integration of VERs.
The Commission appreciates that these requirements go beyond some
existing activities. The Commission nonetheless concludes that the
reforms adopted herein are
[[Page 41487]]
necessary to ensure that Commission-jurisdictional services are being
provided at rates, terms and conditions that are just and reasonable
and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\35\ See, e.g., Ariz. Pub. Service Co., 137 FERC ] 61,023
(2011); NorthWestern Corp., 136 FERC ] 61,119 (2011). We note that
the Joint Initiative indicated in its comments at page 6 that its
first step in offering 30-minute scheduling ``is intended to address
unanticipated events, not to move to half-hour scheduling.'' In
addition, based on business practices posted on OASIS, some
transmission providers reserve the right to suspend 30-minute
scheduling.
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III. Legal Authority To Implement Proposed Reforms
A. Commission Proposal
25. In the Proposed Rule, the Commission preliminarily found that
the practice of hourly scheduling, the lack of VER power production
forecasting, and the lack of a clear mechanism to recover the cost of
providing generator regulation service may be contributing to undue
discrimination and unjust and unreasonable rates in light of the entry
and increasing presence of VERs on the transmission grid. Thus, the
Commission proposed the following three reforms that require public
utility transmission providers to: (1) Amend the pro forma OATT to
require intra-hourly transmission scheduling; (2) amend the pro forma
LGIA to incorporate provisions requiring interconnection customers
whose generating facilities are VERs to provide meteorological and
operational data to public utility transmission providers for the
purpose of improved power production forecasting; and (3) amend the pro
forma OATT to add a generic ancillary service rate schedule, Schedule
10--Generator Regulation and Frequency Response Service, in which
public utility transmission providers will offer to provide regulation
service for transmission customers using transmission service to
deliver energy from a generator located within a public utility
transmission provider's balancing authority area.\36\ The Commission
preliminarily concluded that the proposed rules are necessary to ensure
that rates for Commission-jurisdictional services are just and
reasonable and to remedy undue discrimination in existing transmission
system operations.\37\
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\36\ Throughout this Final Rule the term Balancing Authority is
used as defined by the North American Electric Reliability
Cooperation (NERC). NERC, Glossary of Terms, available at http://www.nerc.com/files/Glossary_of_Terms_2012January11.pdf.
\37\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 23.
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B. Comments
26. Some commenters take issue with the Commission's authority to
mandate the tariff amendments contained in the Proposed Rule. With
regard to forecasting and 15-minute scheduling, EEI and Southern assert
that the Proposed Rule does not articulate a sufficient basis for
changing existing tariff-based scheduling requirements under section
206 of the FPA.\38\ Specifically, EEI and Southern question whether the
Commission is relying upon record findings to support these proposed
requirements. EEI and Southern submit that sections 205 and 206 ``are
simply parts of a single statutory scheme under which all rates are
established initially by the [public utilities], by contract or
otherwise. * * * Thus, FERC plays an essentially passive and reactive
role under section 205.'' \39\ EEI and Southern maintain that these
types of decisions should be left to public utility transmission
providers and RTOs and should be informed by regional conditions and
not dictated on a generic basis.
---------------------------------------------------------------------------
\38\ EEI and Southern argue, for example, that the Commission
must rely upon factual, record findings to support these proposed
mandates. EEI (citing National Fuels v. FERC, 468 F.3d 831, 839-44
(D.C. Cir. 2006)); Southern (citing, e.g., National Fuels, 468 F.3d
831, 839-44).
\39\ EEI (citing Atlantic City v. FERC, 295 F.3d 1,21 (D.C. Cir.
2002) (quoting United Gas Pipe Line Co. v. Mobile Gas Serv. Corp.,
350 U.S. 332341 (1956) and City of Winnfield v. FERC, 744 F.2d 871,
876 (D.C. Cir. 1984)); Southern (citing Atlantic City v. FERC, 295
F.3d 1,21 (D.C. Cir. 2002) (quoting United Gas Pipe Line Co. v.
Mobile Gas Serv. Corp, 350 U.S. 332341 (1956) and City of Winnfield
v. FERC, 744 F.2d 871, 876 (D.C. Cir. 1984)).
---------------------------------------------------------------------------
27. In contrast, NextEra states that assertions that there is no
record evidence not only ignore how current rules disadvantage VERs,
but misunderstand the Commission's authority to promulgate rules of
general applicability. NextEra points out that the Commission does not
have to find that the tariffs or practices of every utility under its
jurisdiction are unjust and unreasonable in order to proceed with a
rulemaking. Rather, NextEra asserts that courts have confirmed that the
Commission is not required to make individual findings when it
exercises its statutory authority to promulgate a rule of general
applicability.
28. Certain commenters also question the Commission's reliance in
this proceeding on its authority to remedy undue discrimination.\40\
Specifically, EEI and Southern take issue with the Commission's
conclusion that procedures (such as hourly scheduling) applied
uniformly to all transmission customers are unduly discriminatory under
the FPA when those procedures arguably have a disparate impact on
different types of transmission customers and/or place those customers
at a competitive disadvantage in wholesale markets. EEI and Southern
submit that the Commission and the DC Circuit have rejected the notion
that facially-neutral technology and customer-blind transmission
scheduling procedures are unduly discriminatory under section 205 of
the FPA because of the effects or impacts of those requirements on
different customer groups.\41\ EEI asks the Commission to clarify that
facially-neutral, technology- and customer-blind operational practices
will not be deemed unduly discriminatory solely by virtue of disparate
impact on dissimilar technologies or customers, and that the Proposed
Rule is not intended as a departure from precedent in determining undue
discrimination.
---------------------------------------------------------------------------
\40\ E.g., Southern; EEI.
\41\ Southern (citing Enron Power Marketing, Inc. v. FERC, 296
F.3d 1148 (D.C. Cir. 2002) (Enron)); EEI (citing Enron, 296 F.3d
1148).
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29. Similarly, Public Power Council questions the sufficiency of
the Commission's evidence of undue discrimination against VERs. Public
Power Council asserts that the Commission has not demonstrated that the
costs of capacity charged to VERs were not incurred for the benefit of
VERs, or would not have been incurred but for the needs of VERs, and
that the costs of capacity were not prudently incurred. Public Power
Council submits that the rules applicable to generation for the payment
of balancing capacity costs are facially neutral, as VERs require more
balancing capacity than non-variable resources. According to Public
Power Council, if a load's characteristics required extraordinary
amounts of balancing capacity, it seems unlikely that it or anyone else
would complain that the rules should be changed to reduce costs. Thus,
Public Power Council argues that a federal policy to promote renewable
generation cannot be translated into an overriding mandate to prefer
VERs.
30. ELCON asserts, with regard to 15-minute scheduling,
forecasting, and Schedule 10 service, that the principle flaw in the
Proposed Rule is its reliance on the supposition that operating
practices favoring the dispatchability of resources are a form of
``preferential treatment,'' and therefore that non-dispatchable
resources such as VERs are being discriminated against. ELCON explains
that the proposals set forth in the Proposed Rule are costly measures
that would apply preferentially to just one class of generation--VERs--
seeking to address discrimination that does not actually exist.
31. Southern asserts that, in instances where a single rate is
found to have disparate cost impacts upon dissimilar customers, such a
result is only considered unduly discriminatory if such differences
cannot be cost-
[[Page 41488]]
justified.\42\ Southern argues that existing scheduling and imbalance
practices are not unduly discriminatory against VERs. Southern explains
that VER customers pay more energy imbalance charges than others
because they impose more imbalance burdens and costs upon the
system.\43\ Similarly, ELCON maintains that the cost causation model of
cost allocation results in greater economic efficiency by retaining a
direct tie between the costs and the benefits of a given project. ELCON
argues that in the instant case, there is no tie to the costs customers
will be forced to bear.
---------------------------------------------------------------------------
\42\ Southern (citing Ala Elec. Coop. v. FERC, 684 F.2d 20, 29
(D.C. Cir. 1982) (Alabama Power)).
\43\ Southern further contends that VERs are not similarly
situated to dispatchable generation for sheduling and imbalance
purposes. Id. (citing City of Vernon v. FERC, 845 F.2d 1042, 1045-46
(D.C. Cir. 1988)).
---------------------------------------------------------------------------
32. Midwest ISO Transmission Owners contend that all generation
resources should be treated on a comparable basis, and none should be
subject to undue discrimination or receive an undue preference. Midwest
ISO Transmission Owners state that in the Midwest ISO this will mean
that VERs are subject to the same requirements as existing resources
unless additional requirements are necessary to maintain
reliability.\44\ ELCON argues that the Commission should apply a
principle of ``source neutrality,'' which it contends will create a
level playing field for all alternative resources including demand
response and combined heat and power. ELCON explains that, without the
adoption of a resource planning paradigm based on source neutrality,
almost any non-traditional resource may fall prey to undue
discrimination with respect to transmission of electric energy and
sales of electric energy for resale in interstate markets.
---------------------------------------------------------------------------
\44\ Midwest ISO Transmission Owners (referencing Proposed Rule,
FERC Stats. & Regs. ] 32,664 at PP 37, 45, 55 (stating that proposed
reforms in intra-hour scheduling and power production forecasting
can enhance reliability).
---------------------------------------------------------------------------
33. On the contrary, NextEra argues that most market rules are not
oriented to aiding VERs, and may in fact present obstacles to VERs.
NextEra states that, even in RTO markets, the fundamental principles
around which markets are designed are day-ahead schedules, economic
dispatch, and the impact of congestion. NextEra points out that none of
these concepts are particularly applicable to VERs, which can have
difficulty producing accurate day-ahead forecasts, are not truly
dispatchable, and have limited ability to choose sites to reduce
congestion. For example, NextEra contends that while nodal
representation of generators may work best for dispatchable units, a
system that was designed around non-dispatchable VERs could include
features such as aggregation and scheduling from a portfolio of
generators that might be staggered geographically, so as to reduce
variability and forecasting errors and allow pooling of energy
imbalances and deviations.
34. NextEra explains that when the Commission remedies unfair rules
and practices, it is not doing so to create a preference for the type
of entity that was being harmed, but rather to benefit the market and
consumers. Thus, NextEra maintains that Commission action to provide
greater flexibility, promote innovation or foster participation by new
market entrants will ultimately benefit energy markets and consumers,
even though the measure itself focuses on changes or incentives for one
type of market participant.
35. Finally, with regard to meteorological forecasting in
particular, Southern contends that such forecasting practices are
beyond the scope of the Commission's authority. Southern states that
courts have recognized that the Commission ``is a `creature of
statute,' having no constitutional or common law existence or
authority, but only those authorities conferred upon it by Congress.''
\45\ Southern contends that public utilities have long engaged in
meteorological forecasting for load forecasting and dispatch purposes.
Southern argues that there never has been an indication that such
practices were within the scope of the Commission's jurisdiction, and
the advent of VER generation has not added such forecasting to the
scope of the Commission's authority.
---------------------------------------------------------------------------
\45\ Southern (citing Cal. Indep. Sys. Operator Co. v. FERC, 372
F.3d 395, 398 (D.C. Cir. 2004) (citing Atlantic City Elec. Co. v.
FERC, 295 F.3d at 8)).
---------------------------------------------------------------------------
C. Commission Determination
36. The Commission concludes that it has authority under section
206 of the FPA to adopt the reforms set forth in this Final Rule.
Section 313(b) of the FPA makes Commission findings of fact conclusive
if they are supported by substantial evidence.\46\ When applied in a
rulemaking context, ``the substantial evidence test is identical to the
familiar arbitrary and capricious standard.'' \47\ The Commission thus
must show that a ``reasonable mind might accept'' that the evidentiary
record here is ``adequate to support a conclusion,'' \48\ that this
Final Rule is needed to address barriers to the integration of VERs by
remedying challenges that may be causing undue discrimination and
increased costs ultimately borne by consumers. As explained below, the
Commission has met its burden.
---------------------------------------------------------------------------
\46\ 16 U.S.C. 825l(b).
\47\ Wisc. Gas Co. v. FERC, 770 F.2d 1144, 1156 (1985); see also
Associated Gas Distrib. v. FERC, 824 F.2d 981, at 1018 (D.C. Cir.
1987).
\48\ Dickenson v. Zurko, 527 U.S. 150, 155 (1999).
---------------------------------------------------------------------------
37. As discussed throughout this Final Rule, the reforms adopted in
this proceeding are intended to ensure that rates for jurisdictional
services remain both just and reasonable and are not unduly
discriminatory or preferential. In this way, the reforms contained in
this Final Rule build on the work of Order No. 890, in which the
Commission made several reforms to the pro forma OATT, in part because
of a recognition that the mix of generation resources on the system was
changing and that not all generation resources were similarly
situated.\49\ Like the reforms instituted in Order No. 890, the reforms
adopted herein are designed to remedy deficiencies in existing
requirements that can cause the rates, terms, and conditions of
jurisdictional services to become unjust and unreasonable or unduly
discriminatory or preferential.
---------------------------------------------------------------------------
\49\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 2 (citing
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 5. The Commission
further recognized that intermittent resources, such as wind power,
have a limited ability to control their output, and that this
limitation supports tailoring certain requirements to the special
circumstances presented by this type of resource. Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 663 (requiring that generator
imbalance provisions account for the special circumstances presented
by intermittent generators).
---------------------------------------------------------------------------
38. The basis for adopting changes to the pro forma OATT and pro
forma LGIA is discussed in the sections below addressing reforms to
transmission scheduling practices and the reporting of meteorological
data. There the Commission concludes that changes to scheduling
practices are necessary in order to ensure that charges for generator
imbalance service under schedule 9 of the pro forma OATT and for
generator regulation service, as relevant, are just and reasonable and
not unduly discriminatory. The Commission also concludes that, without
the reporting requirements adopted herein, the terms of the pro forma
LGIA may impair the ability of public utility transmission providers to
develop and deploy power production forecasting, which in turn can lead
to rates for jurisdictional services that are unjust and unreasonable
or unduly discriminatory.
39. The Commission concludes that we have the authority to make
these determinations under applicable precedent, including National
Fuel. In that case, the court found that the
[[Page 41489]]
Commission had not met the substantial evidence standard when it sought
to extend its Standards of Conduct that regulate natural gas pipelines'
interactions with their marketing affiliates to their interactions with
their non-marketing affiliates. The court noted that it had previously
upheld the Standards of Conduct as applied to marketing affiliates
because the Commission had demonstrated both a theoretical threat,
namely that pipelines could grant undue preferences to their marketing
affiliates, and substantial record evidence that such abuse had
actually occurred.\50\ In considering the Commission's order extending
the Standards to non-marketing affiliates, the court found that the
Commission had cited a theoretical threat of undue preference, but had
not cited a single example of actual abuse by non-marketing affiliates.
It concluded that instead of providing evidence of a real problem with
respect to non-marketing affiliates, the Commission had relied either
on examples of abuse by marketing affiliates, and therefore already
covered by the old Standards, or on comments from the rulemaking that
merely reiterated a theoretical potential for abuse.\51\ The court
remanded the matter and noted that if the Commission chose to proceed
with promulgating the new Standards, it would have to develop a factual
record to support them. If the Commission decided instead to rely
solely on a theoretical threat, it would need to show how this threat
justified the costs that the Standards would create.\52\
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\50\ National Fuel, 468 F.3d at 840.
\51\ Id. at 841.
\52\ Id. at 844.
---------------------------------------------------------------------------
40. Our actions in this Final Rule are consistent with the
standards that the court set forth in National Fuel. We conclude that,
in light of the increasing deployment of VERs on the nation's
transmission system, the reforms adopted herein are necessary to
correct operational practices that can limit the cost-effective
integration of VERs into the transmission system consistent with open
access principles. In other words, the problem that the Commission
seeks to resolve represents a ``theoretical threat,'' in the words of
the National Fuel decision, the features of which are discussed
throughout the body of this Final Rule in the context of each of the
reforms adopted herein. This threat is significant enough to justify
the reforms imposed by this Final Rule. It is not one that can be
addressed adequately or efficiently through the adjudication of
individual complaints.\53\ In the terminology of National Fuel, the
remedy we adopt is justified sufficiently by the ``theoretical threat''
identified herein, even without ``record evidence of abuse.'' The
actual experiences of problems cited in the record herein provide
additional support for our action, but are not necessary to justify the
remedy.
---------------------------------------------------------------------------
\53\ Individual adjudications by their nature focus on discrete
questions of a specific case. Rules setting forth general principles
are necessary to ensure that adequate processes are in place.
---------------------------------------------------------------------------
41. Citing Enron, Southern and EEI also argue that the Commission
does not have the authority to remedy undue discrimination in
situations where facially neutral operational practices result in a
disparate impact on different market participants. The Commission
disagrees. Enron involved an OATT Filing by a public utility (Entergy)
in which the utility sought to require point-to-point transmission
customers to designate specific sources and sinks for transmission
service. The proposal also set forth what the utility would accept as a
valid source or sink, prohibiting a generator (or generation-only
control area) from being a sink, and prohibiting a load (or load-only
control area) from being a source.\54\ Customers objected to the
proposal, arguing that the provision would not limit Entergy's ability
to reserve capacity and schedule in and out of its control area because
it had load and generation within its control area, but would prohibit
similar transactions from customers operating control areas completely
surrounded by Entergy that sought to set up transactions in and out of
those control areas. The Commission evaluated Entergy's proposal under
the applicable standard of review, i.e., whether the OATT Filing was
consistent with or superior to the Order No. 888 pro forma OATT. The
Commission accepted the proposal, and the United States Court of
Appeals for the District of Columbia Circuit upheld the decision.\55\
---------------------------------------------------------------------------
\54\ Enron, 296 F.3d at 1151.
\55\ Id. at 1153-54.
---------------------------------------------------------------------------
42. We find that commenters' reliance on Enron is misplaced. In
Enron, the Commission reviewed a tariff filing made under section 205
of the FPA to determine if it was consistent with or superior to the
pro forma OATT. The scope of that analysis is not analogous to that of
our inquiry in this proceeding, which is to determine if changes to the
pro forma OATT and pro forma LGIA are necessary to ensure that rates
for jurisdictional services remain just and reasonable and not unduly
discriminatory. In any event, to the extent that Enron may be relevant
to a rulemaking proceeding of general applicability, Southern and EEI
appear to misunderstand the result in Enron. In that case, the court
found that it was neither arbitrary nor capricious for the Commission
to accept a tariff provision forbidding the designation of a generator-
only control area as a sink and a load-only control area as a source as
comparable to the pro forma OATT.\56\ In addition to this holding, the
court indicated that it was sufficient for the Commission to address
comparability of an OATT (the applicable standard in that proceeding)
``on the basis of the terms and conditions offered to customers, not on
the usefulness of those terms and conditions to a particular customer
because of that customer's capacities and needs,'' noting also that the
Commission found that the provision was not discriminatory.\57\
---------------------------------------------------------------------------
\56\ Id. at 1151-52.
\57\ Id. at 1151. The court further found that the Commission
adequately addressed charges that the provision would lead to
discriminatory treatment by accepting the utility's commitment to
apply the provision on a nondiscriminatory basis.
---------------------------------------------------------------------------
43. Enron did not, as Southern and EEI suggest, reject the notion
that facially-neutral, technology- and customer-blind operational
practices could be found to be unduly discriminatory because of the
effects or impacts of those requirements on different customer groups.
Instead, the relevant Enron dicta indicate that the Commission could
sustain a determination that a tariff provision is comparable to the
pro forma OATT where it offers the same terms and conditions to
customers, notwithstanding a difference in how different customers will
use or benefit from those tariff provisions.\58\ However, nothing in
Enron mandates that result.
---------------------------------------------------------------------------
\58\ Id.
---------------------------------------------------------------------------
44. Our conclusion that Southern and EEI erred in their
interpretation of Enron is bolstered by other cases included in the
comments of both parties. For example, Southern and EEI cite Alabama
Power for the proposition that, in instances where a single rate is
found to have disparate cost impacts on dissimilar customers, such a
result is only considered unduly discriminatory if the differences
cannot be cost justified.\59\ In Alabama Power, the issue for the court
was whether an application of the same rate to two groups of customers
that were similar in many respects may nevertheless violate statutory
prohibitions against unduly discriminatory rate schemes. That case
involved rate filings by a utility that
[[Page 41490]]
applied the same rate to two groups of wholesale service customers. One
group alleged that this single rate represented a misallocation of
costs, resulting in that group paying significantly more (and the other
paying significantly less) than the costs for which its members were
responsible. The court held that notwithstanding the fact that the same
rate applied to both groups of customers, the Commission was obligated
to evaluate whether the different costs imposed by those two groups
rendered the use of a single rate unduly discriminatory.\60\
---------------------------------------------------------------------------
\59\ Southern (citing Alabama Power, 684 F.2d at 29); EEI
(citing Alabama Power, 684 F.2d 20).
\60\ Alabama Power, 684 F.2d at 28-29.
---------------------------------------------------------------------------
45. Southern argues that a finding in the Proposed Rule--that
existing hourly transmission scheduling protocols expose transmission
customers to ``excessive or unduly discriminatory generator imbalance
charges''--may run afoul of Alabama Power because VER customers require
greater amounts of imbalance service and therefore should be required
to pay more in the way of imbalance charges.\61\ Southern and EEI
contend that, because VERs are not similarly situated to dispatchable
generation for scheduling and imbalance purposes, existing scheduling
and imbalance practices cannot be unduly discriminatory toward
VERs.\62\ Similarly, ELCON argues that the Proposed Rule would require
all ratepayers to subsidize the integration of VERs despite not
receiving any benefits, thereby violating cost causation principles.
---------------------------------------------------------------------------
\61\ Southern (citing Proposed Rule, FERC Stats. & Regs. ]
32,664 at P 37).
\62\ Both Southern and EEI cite additional authority for this
point, i.e., that in order to demonstrate that it was unduly
discriminated against, a party must show that it is similarly
situated to another party receiving different treatment. See EEI
(citing Ark. Elec. Energy Consumers v. FERC, 290 F.3d 362 (D.C. Cir.
2002) (``a rate is not `unduly' preferential or `unreasonably' ''
discriminatory in violation of the FPA if disparate effect of
transmission or sale of electric energy by the jurisdictional
utility can justify the disparate effect'')); Southern (citing City
of Vernon v. FERC, 845 F.2d 1042, 1045-46 (D.C. Cir. 1988) (``The
Commission's opinion sets forth a two-part test for discriminatory
treatment where different rates or services are offered, requiring a
showing that the unequally treated customers are `similarly
situated,' and that the service sought is the `same service'
actually offered elsewhere.'') & n.2 (``FERC has typically relied on
factors like these in defining a prima facie case of undue
discrimination.''); see, e.g.,Sacramento Mun. Util. Dist. v. FERC,
474 F.3d 797, 802 (D.C. Cir. 2007) (``In order for PG&E's refusal to
negotiate a successor agreement with [Sacramento Municipal Utility
District (SMUD)] to constitute undue discrimination, SMUD must
demonstrate it is similarly situated to Western.'').
---------------------------------------------------------------------------
46. As with commenters' reliance on Enron, we find that commenters'
reliance on Alabama Power is misplaced. The Commission is not
determining whether a single rate imposed on two groups of customers
may unduly discriminate against one of those groups. Instead, the
Commission is promulgating a generic rule that amends the scheduling
requirements of the pro forma OATT to remedy practices throughout the
industry that may be causing jurisdictional rates to be excessive or
unduly preferential. Accordingly, the task before the Commission is not
comparing the impact of a concrete rate proposal on distinct and
readily identifiable customers or classes. Rather, the Commission is
broadly evaluating whether the pro forma OATT contains the appropriate
set of requirements to ensure that rates for all customers remain just
and reasonable and not unduly discriminatory. As in Order No. 890, the
Commission is acting in part to remedy OATT provisions that may allow
public utility transmission providers to treat some customers in an
unduly discriminatory manner. Such an endeavor necessarily requires the
Commission to take notice of the general developments in the electric
industry in deciding what generic reforms may be needed to ensure that
the pro forma OATT does not unduly discriminate against any one class
of customers.\63\
---------------------------------------------------------------------------
\63\ See Transmission Access Policy Study Group v. FERC, 225
F.3d 667 (D.C. Cir. 2000) (TAPS) (affirming Order No. 888 rulemaking
based on general findings, rejecting utility arguments that FERC
must have substantial evidence and make specific factual findings);
Wisc. Gas Co. v. FERC, 770 F.2d 1144 (affirming that Commission need
not make individual findings regarding each affected entity but can
rely on a broader record in promulgating rule of general
applicability); Associated Gas Distrib. v. FERC, 824 F.2d 981
(affirming that the Commission is not required to have empirical
data for all the propositions upon which its order depended before
promulgating a rule).
---------------------------------------------------------------------------
47. In Order No. 890, the Commission recognized that the mix of
generation resources on the system was changing and that not all
generation resources were similarly situated.\64\ In response, the
Commission instituted reforms that recognized the unique nature of
intermittent resources, tailoring certain requirements to the special
circumstances presented by this type of resource.\65\ We again
recognize that VERs, by definition,\66\ are not similarly situated to
conventional, dispatchable generators and that reforms to the pro forma
OATT are necessary to ensure that these resources are treated in a fair
and not unduly discriminatory manner. Simply because VERs are not
similarly situated in all respects to conventional, dispatchable
generators, it does not follow, as Southern and EEI assert, that
existing pro forma OATT provisions that place a disproportionate burden
on VERs are just and reasonable.\67\ The more frequent scheduling
intervals required by this Final Rule will enable VERs, as well as
other generators, to schedule transmission service accurately based on
forecasted energy output. This will mitigate VERs' exposure to
imbalance charges, while at the same time giving public utility
transmission providers a better understanding of expected energy flows
on their systems.
---------------------------------------------------------------------------
\64\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 5.
\65\ Id. P 663 (requiring that generator imbalance provisions
account for the special circumstances presented by intermittent
generators).
\66\ See supra note 1 (defining VER).
\67\ See Alabama Power, 684 F.2d at 23-24 (``It matters little
that the affected customer groups may be in most respects similarly
situated--that is, that they may require similar types of service at
similar (even if varying) voltage levels. If the costs of providing
service to one group are different from the costs of serving the
other, the two groups are in one important respect quite
dissimilar.'').
---------------------------------------------------------------------------
48. The Commission does not need to make specific findings with
respect to each affected entity so long as the agency's factual
determinations are reasonable.\68\ As further discussed herein, the
Final Rule amends the pro forma OATT in ways that will limit
uncertainty and provide additional control over scheduling, which
should reduce imbalance charges for all customers. The proposed reforms
will further benefit customers and the market as a whole by providing
increased flexibility and encouraging innovation and participation by
new market participants.\69\ While the Commission commenced this
proceeding as a response to the significantly increasing penetration of
VERs into the nation's generation portfolio, the Commission's purpose
is not to favor VERs over other forms of generation (or demand)
resources. Quite the contrary, a primary goal of this proceeding is to
remove obstacles that can have a discriminatory impact on the ability
of VERs to compete in the marketplace and that can otherwise result in
unjust and unreasonable rates for all market participants.\70\
---------------------------------------------------------------------------
\68\ TAPS, 225 F.3d at 688 (citing Wisc. Gas Co. v. FERC, 770
F.2d at 1158).
\69\ Cf. Order No. 679, Promoting Transmission Investment
through Pricing Reform, Order No. 679, FERC Stats. & Regs. ] 31,222,
at PP 131, 176, 224, order on reh'g, Order No. 679-A, FERC Stats. &
Regs. ] 31,236, at P 77 (2006), order on reh'g, Order No. 679-B, 119
FERC ] 61,062 (2007). The Commission does not authorize these
measures to provide a unilateral benefit to transmission owners but
rather to encourage the development of needed transmission, which
has broader benefits to the market and consumers.
\70\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 23.
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49. Finally, in response to Southern, the Commission notes that it
is not
[[Page 41491]]
asserting jurisdiction over the practice of power production
forecasting in this Final Rule. Rather, the Commission is adopting
changes to the pro forma LGIA to impose reporting requirements on
interconnection customers whose generating facilities are VERs. As
discussed in further detail later in this Final Rule, power production
forecasting can be used by public utility transmission providers to
significantly reduce operating costs associated with the integration of
VERs interconnected to their systems.\71\ However, the ability of
public utility transmission providers to engage in power production
forecasting may be limited without data from interconnected VERs. In
order to facilitate a public utility transmission provider's use of
power production forecasting to reduce its operating costs, the
Commission is amending the requirements of the pro forma LGIA to impose
a data reporting requirement as a condition of interconnection service
for interconnection customers whose generating facilities are VERs.
---------------------------------------------------------------------------
\71\ See infra Sec. IV.B.1 (Data Requirements).
---------------------------------------------------------------------------
50. The question then is whether the Commission has jurisdiction to
condition the grant of interconnection service on the reporting of
meteorological and outage data by interconnection customers whose
generating facilities are VERs as a practice affecting rates subject to
the Commission's jurisdiction under the FPA.\72\ As the Commission
explained in Order No. 2003, interconnection service is a component of
open access transmission service, subject to the Commission's
regulation under sections 205 and 206 of the FPA.\73\ The reporting of
meteorological and outage data by VER customers taking jurisdictional
interconnection service has a direct affect on the ability of the
public utility transmission provider to efficiently manage the VER
integration through the development and deployment of power production
forecasting. Failure to require the reporting of this data could limit
the public utility transmission provider's ability to develop and
deploy power production forecasts and, in turn, its attempts to
efficiently commit or de-commit resources providing regulation
reserves, potentially resulting in rates for reserve-related services
that are unjust and unreasonable or unduly discriminatory. It is
therefore reasonable for the Commission to conclude that it is within
our jurisdiction to implement the data reporting requirements of this
Final Rule as a condition of interconnection service.
---------------------------------------------------------------------------
\72\ See Cal. Indep. Sys. Oper. v. FERC, 372 F.3d 395 (D.C. Cir.
2004).
\73\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at 12.
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IV. Proposed Reforms
A. Intra-Hour Scheduling
51. The first of the two reforms adopted in this Final Rule relates
to the intervals at which transmission customers may submit
transmission schedules under the pro forma OATT. As discussed below,
the Commission amends the pro forma OATT to provide all transmission
customers the option of using more frequent transmission scheduling
intervals within each operating hour, at 15-minute intervals. The
Commission concludes this change to existing operational practices is
necessary in order to ensure that charges for generator imbalance
service under Schedule 9 of the pro forma OATT and for generator
regulation service, as relevant, are just and reasonable and not unduly
discriminatory.
1. Intra-Hour Scheduling Requirement
a. Commission Proposal
52. In the Proposed Rule, the Commission preliminarily found that
hourly transmission scheduling protocols are no longer just and
reasonable and may be unduly discriminatory as the default scheduling
time periods required by the pro forma OATT. Specifically, the
Commission preliminarily found that existing hourly transmission
scheduling protocols expose transmission customers to excessive or
unduly discriminatory generator imbalance charges and are insufficient
to provide system operators with the flexibility to manage their system
effectively and efficiently. Therefore, the Commission proposed to
amend sections 13.8 and 14.6 of the pro forma OATT to provide
transmission customers the option to schedule transmission service on
an intra-hour basis, at intervals of 15 minutes. The Commission noted
that its proposed reform would allow for intra-hour scheduling
adjustments and that it did not propose changes to the hourly
transmission service reservation provided in the OATT.\74\
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\74\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 39 & n.89.
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53. The Commission acknowledged in the Proposed Rule that a number
of public utility transmission providers already have begun
implementing intra-hour scheduling practices. The Commission stated
that, while these individual reforms are important steps toward the
efficient integration of VERs, it believed that it also is important to
establish 15-minute scheduling periods as the default scheduling
process. At the same time, the Commission acknowledged arguments that
regional differences should be respected when developing an
implementation process and that any Commission action should not
negatively affect ongoing industry efforts. In that regard, the
Commission sought comment on the best approach for implementing the
proposed intra-hour scheduling reforms. The Commission recognized that
an optimal implementation approach should support ongoing industry
efforts and may consider regional differences, such as the amount of
VERs present in that region. In proposing implementation approaches,
the Commission encouraged commenters to consider any impacts on
transmission customers scheduling across multiple systems and whether
these impacts diminish the benefits of implementing intra-hour
scheduling.\75\
---------------------------------------------------------------------------
\75\ Id. PP 42-43.
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54. To understand more fully the modifications that this proposed
reform may require, the Commission sought comment on the specific
hardware, software, and personnel changes that are necessary to
implement intra-hour scheduling. The Commission further inquired as to
whether there would be any additional impacts on relatively small
public utility transmission providers, and how to best facilitate this
reform for small public utility transmission providers.
b. Comments
i. Obligation to Offer Intra-Hour Scheduling
55. A number of commenters support the Commission's proposal to
require public utility transmission providers to offer intra-hour
scheduling,\76\ although some seek clarifications or modifications of
the proposal. Additionally, commenters disagree as to the appropriate
period of time for submitting intra-hour schedules. These commenters
generally agree that intra-hour scheduling would enable transmission
customers to align transmission schedules with actual generation output
more effectively, reduce the need for transmission providers to carry
expensive operating
[[Page 41492]]
reserves, and provide for greater system flexibility by utilizing
available resources in a more efficient manner.
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\76\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP
Energy; California ISO; CESA; CMUA; CEERT; Center for Rural Affairs;
Clean Line; CGC; Defenders of Wildlife; Environmental Defense Fund;
EPSA; Exelon; First Wind; FriiPwr; Independent Power Producers
Coalition--West; Independent Energy Producers; ITC Companies;
NextEra; NaturEner; Organization of Midwest ISO States; Oregon and
New Mexico PUC; Public Interest Organizations; Powerex; SWEA; Tacoma
Power; Tres Amigas; TVA; Vestas; Viridity Energy; Vote Solar;
Western Grid; Xcel.
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56. For example, EPSA states that the option of 15-minute
scheduling would expand the availability of flexible generation
resources and demand response resources to provide additional liquidity
and consistency in the market. Exelon argues that implementing intra-
hour scheduling will reduce supply-side uncertainty, which should allow
resources to be more optimally selected and allocated than otherwise
would be the case. Powerex contends that shorter scheduling intervals
would allow the use of more accurate forecasts that are closer to the
operating time-frame. Joined by CEERT and others, Powerex argues that
intra-hour scheduling would increase transmission system flexibility
and efficiency, providing grid operators with more options for
scheduling resources during each hour and decreasing the need for (and
costs of) ancillary services needed for reliable integration of
VERs.\77\ The Center for Rural Affairs asserts that making intra-hour
scheduling available is essential for public utility transmission
providers and balancing authorities seeking to provide system balance
with increasing generation from VERs.
---------------------------------------------------------------------------
\77\ E.g., CEERT; Powerex; Public Interest Organizations;
Vestas.
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57. While acknowledging that some stakeholders in this proceeding
oppose the mandatory nature of the Commission's proposal, disagree
about scheduling costs, and question the reliability impacts of the
proposed reforms, Public Interest Organizations state that almost all
stakeholders have acknowledged that intra-hour scheduling does improve
scheduling accuracy and decrease the need for energy imbalance
services. Public Interest Organizations, joined by Environmental
Defense Fund and Argonne National Lab, contend that intra-hour
scheduling, as compared to hourly scheduling protocols, allows for a
more accurate prediction of the variable generation that can be
delivered within the market interval, reducing the need to procure
expensive regulation or energy imbalance services.\78\ NaturEner
agrees, arguing that shorter scheduling intervals would allow for more
frequent generation adjustments, thus, decreasing the negative impacts
on both the transmission system and the grid from frequent generation
disruptions. Iberdrola similarly contends that moving toward smaller
intra-hour scheduling intervals will provide incentives for more
complete and efficient scheduling practices and eliminate other
outdated and discriminatory operating practices.
---------------------------------------------------------------------------
\78\ E.g., Argonne National Lab; Environmental Defense Fund;
Public Interest Organizations.
---------------------------------------------------------------------------
58. California ISO states that continuing to require resources to
match hourly transmission schedules would perpetuate inefficient and
burdensome operational requirements. Tres Amigas contends that current
scheduling practices have been associated with underutilized
transmission assets and sub-optimal operating practices resulting in
inefficient curtailment of generation. BP Energy asserts that 15-minute
scheduling intervals will increase the ability of a transmission
customer scheduling energy from a VER to manage the scheduled input
and, therefore, its imbalance costs. Vestas notes that all generators,
regardless of fuel type, will be able to track their schedules more
closely with actual levels of production as a result of intra-hour
scheduling. Vestas explains that, if a large fossil-fueled resource
suffers an outage or derate within an hour, the ability to change its
schedule earlier than the next clock hour can provide significant
benefits to both the generator and the transmission system operator.
Clean Line contends that intra-hour scheduling is likely to have
benefits independent of variable generation integration, stating that
sub-hourly variations in load could be managed in a more cost-effective
manner. Also, A123 contends that shorter scheduling intervals will help
OATT markets incorporate the benefits of high-ramp, limited energy
resources like storage.\79\
---------------------------------------------------------------------------
\79\ A ramp rate is the rate, expressed in megawatts per minute,
that a resources changes its output. See NERC Glossary of Terms,
available online at http://www.nerc.com/files/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------
59. However, other commenters oppose mandatory intra-hour
scheduling, arguing generally that current scheduling practices are
neither preferential nor unduly discriminatory.\80\ For example, ELCON
states that the Commission's proposals are costly measures that would
apply preferentially to just one class of generation--VERs--in order to
address discrimination that does not actually exist. Some commenters
argue that further study of the need for intra-hour scheduling should
be undertaken prior to mandating the practice. Several of these
commenters assert that the Commission should not require the
implementation of 15-minute intra-hour scheduling until certain impacts
are better understood.\81\ LADWP submits that intra-hour scheduling
should not be implemented until it has been fully vetted and researched
to assess operational capabilities and coordination.
---------------------------------------------------------------------------
\80\ E.g., ELCON; Midwest ISO; NV Energy; Southern.
\81\ E.g., California PUC; LADWP; NorthWestern; NV Energy;
Pacific Gas & Electric.
---------------------------------------------------------------------------
60. Some commenters argue that the Commission's proposed reform may
not lead to a reduction in aggregate reserve costs. These commenters
contend that the implementation of intra-hour scheduling does not
negate the inherent variability of VERs and, therefore, the cost of
providing balancing services is merely shifted, rather than mitigated,
by intra-hour scheduling.\82\ For example, Avista explains that, while
the host balancing authority will provide a reduced amount of balancing
reserves within each scheduling period, a significant portion of this
variability is being covered by the sink balancing authority or the
load serving entity (LSE). Avista contends the sink balancing authority
or LSE will incur increased balancing costs to follow the fluctuating
VER schedule against a relatively more constant load, thereby shifting
the cost of managing that variability as opposed to creating
substantial cost savings through intra-hour scheduling. If the host
balancing authority area and the sink balancing authority area are the
same, Avista argues that no cost savings or reduction in reserves is
accomplished by the proposed scheduling reforms. Iberdrola argues that
implementing intra-hour scheduling absent a market for dispatchable
resources to manage variability could potentially be more harmful than
helpful to VER integration. Duke argues that, due to the inherent
variability of VERs, more regulating reserves will be needed regardless
of the scheduling interval. While operating experience may diminish the
need for regulating reserves over time, Duke contends that the level of
regulating reserves will ultimately be maintained at a higher level
than required today. M-S-R Public Power Agency encourages the
Commission to consider the effectiveness of reducing overall
intermittency management obligations further before implementing an
intra-hour scheduling reform.
---------------------------------------------------------------------------
\82\ E.g., Avista; Bonneville Power; M-S-R Public Power Agency;
Xcel.
---------------------------------------------------------------------------
61. With regard to the appropriate time interval for intra-hour
scheduling, a number of commenters support the Commission's proposal to
require public utility transmission providers to offer intra-hour
scheduling at 15-minute intervals.\83\ Many of these commenters
[[Page 41493]]
agree that a scheduling interval of 15-minutes or shorter provides a
number of benefits such as lowering the costs related to integrating
VERs into the market and operational benefits. Argonne National Lab
states that requiring transmission providers to schedule resources with
a frequency of at least every 15 minutes would provide benefits to all
supply and demand resources in the power system, not only VERs. Several
commenters argue that scheduling in 15-minute intervals would reduce
imbalance charges through more accurate schedules.\84\ EPSA notes that
the proposed 15-minute scheduling interval is consistent with NERC
recommendations for achieving greater flexibility while meeting
relevant reliability requirements.\85\ Exelon asserts that 15-minute
scheduling is an industry best practice and that the Commission should
set a deadline by which all transmission providers must conform.
---------------------------------------------------------------------------
\83\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP
Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC;
Defenders of Wildlife; Environmental Defense Fund; EPSA; Exelon;
First Wind; Independent Energy Producers; ITC Companies; NaturEner;
Organization of Midwest ISO States; Oregon & New Mexico PUC;
Powerex; Public Interest Organizations; SWEA; Tres Amigas; Viridity
Energy; Vote Solar; Western Grid; Xcel.
\84\ E.g., BP Energy; CEERT; CGC; Defenders of Wildlife; Duke;
NextEra; Public Interest Organizations; SEIA; Vestas; Xcel.
\85\ EPSA (citing NERC April 12, 2010 Response to NOI at 17-18).
---------------------------------------------------------------------------
62. Vestas acknowledges that a shortened scheduling interval must
strike a balance between the benefits of increased certainty and
reduced variability resulting from customers' ability to more closely
match their schedules with their anticipated output and any increased
complexity and technical issues that could result if the scheduling
interval is too short. Vestas contends that a 15-minute scheduling
window provides a reasonable compromise between the current hour and
the even shorter 5-minute intervals utilized in certain RTO markets.
Oregon & New Mexico PUC agree that as more wind and solar generation
are integrated into the system, shorter intra-hour intervals will
generate greater cost savings than longer intervals. Oregon & New
Mexico PUC urge the Commission to adopt a minimum standard for
transmission scheduling at 15-minute intervals to focus industry
efforts on implementing a consistent standard rather than debating the
appropriate interval.
63. Some commenters are concerned that the proposed 15-minute
scheduling interval is too long.\86\ While supportive of 15-minute
scheduling as an interim step, several commenters recommend that the
Commission require public utility transmission providers to move to
shorter scheduling intervals.\87\ RenewElec asserts that 15-minute
scheduling may not be sufficient for the integration of large amounts
of VERs. As an option for increasing flexibility without decreasing the
15-minute scheduling period, SEIA asks the Commission to clarify that
generators may submit 15-minute schedules with different output levels
at the beginning and end of the 15-minute period to reflect anticipated
ramps to manage the variations in diurnal ramping of solar resources.
Vote Solar echoes the concerns of SEIA with regard to solar diurnal
ramping and argues for scheduling intervals more granular than 15-
minutes to accommodate wide-area balancing. Vote Solar recommends that
the Commission additionally require a 5-minute intertie scheduling
interval. However, EEI cautions that if the Commission decides to move
forward with the rule as proposed, the scheduling interval should be no
less than 15 minutes as it may undermine the reliable operation of the
system.
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\86\ E.g., Environmental Defense Fund; FriiPower; Independent
Power Producers Coalition-West; RenewElec; SEIA; Vestas.
\87\ E.g., Environmental Defense Fund; Independent Power
Producers Coalition-West; RenewElec.
---------------------------------------------------------------------------
64. Other commenters argue that the proposed 15-minute scheduling
interval is too short.\88\ Several commenters recommend an initial 30-
minute intra-hour scheduling interval to coincide with current regional
initiatives or as a general first step.\89\ Some commenters argue that
the Commission should use the output of ongoing regional initiatives to
determine whether a 15-minute scheduling interval is necessary, or
whether another mechanism is the desired method to reduce VER
integration costs.\90\ EEI states that, if there is no demand for
intra-hour scheduling, investments to implement 15-minute scheduling
would be unnecessary. NorthWestern expresses uncertainty as to whether
15-minute scheduling would provide benefits greater than those achieved
through 30-minute scheduling. Southern California Edison suggests that
a 30-minute scheduling interval is sufficient as it can capture
forecast error reductions, align with the commitment capabilities of
most integrating resources, and reduce the need for additional
administrative overhead. Iberdrola recommends that the Commission allow
public utility transmission providers to provide intra-hour schedules
at 30-minute intervals as an interim step to participation in an energy
imbalance market.
---------------------------------------------------------------------------
\88\ E.g., LADWP; Montana PSC; NV Energy; Puget.
\89\ E.g., Bonneville Power; California ISO; California PUC;
CMUA; Montana PSC; NorthWestern; NV Energy; Snohomish County PUD;
Southern California Edison; WUTC.
\90\ E.g., Bonneville Power; California PUC; CMUA; FirstEnergy;
NorthWestern; Snohomish County PUD; Southern California Edison.
---------------------------------------------------------------------------
65. Some commenters contend that a 15-minute scheduling interval
does not support the standard 20-minute generator/scheduling ramp rate
in the West.\91\ Tacoma Power explains that continuing to use 20-minute
ramps would create interface problems with the receipt of schedules on
a 15-minute interval. Bonneville Power similarly argues that scheduling
on a 15-minute interval would result in almost continuous ramping in a
way that 30-minute scheduling does not, and that the resulting
reduction in dynamic transfer capability could preclude implementation
of other options for reducing VER integration costs. WestConnect
asserts that this may result in a disparity in the accurate scheduling
of VERs and the system operator's ability to efficiently integrate VERs
under restricted ramping intervals.
---------------------------------------------------------------------------
\91\ E.g., LADWP; NorthWestern; PNW Parties; Tacoma Power;
WestConnect.
---------------------------------------------------------------------------
66. Bonneville Power and Xcel request clarification that ``intra-
hour scheduling adjustments'' include both adjustments to existing
schedules and the submission of new schedules.\92\ MidAmerican requests
clarification as to whether intra-hour scheduling is intended to be
available only within the current hour or also in future hours.
---------------------------------------------------------------------------
\92\ Bonneville Power; Xcel.
---------------------------------------------------------------------------
ii. Consistency in Scheduling Requirements
67. Commenters differ regarding whether the Commission should adopt
a consistent intra-hour scheduling requirement for all transmission
providers under the pro forma OATT. If the Commission decides to move
forward with its proposal, EEI recommends that the Commission require a
uniform, consistent scheduling interval throughout each
interconnection. EEI contends that this will allow for the development
of uniform and consistent intervals in reliability standards and
business practices and also promote accuracy of results. A number of
other commenters agree that consistent scheduling intervals are needed
in order for intra-hour scheduling to occur across balancing authority
areas.\93\ For
[[Page 41494]]
example, NorthWestern and Southern contend that, unless all public
utility transmission providers within an interconnection are required
to comply with the same intra-hour scheduling interval, intra-hour
scheduling may erode a utility's ability to maintain reliability.
---------------------------------------------------------------------------
\93\ E.g., Argonne National Lab; EEI; Iberdrola; Independent
Power Producers Coalition-West; NaturEner; NorthWestern; NRECA;
Oregon & New Mexico PUC; Public Interest Organizations; Puget;
Southern California Edison; Southern; and Tres Amigas.
---------------------------------------------------------------------------
68. Public Interest Organizations agree that there is a need to
apply consistent scheduling obligations across the country in order to
avoid undue discrimination against VERs and argue that the benefits of
15-minute intra-hour scheduling will apply throughout the system, not
just to VERs. If the Commission decides to allow for a public utility
transmission provider to propose variations to 15-minute scheduling,
Public Interest Organizations suggest that the entity be required to
demonstrate why a variation is necessary and show that the proposed
alternative will be equally effective or superior to the Commission's
proposal. NextEra points out that the arguments favoring regional
variations in scheduling requirements ignore the fact that many regions
have no overall regional body or authority with sufficient ability to
ensure consistency in resolving issues regarding VER integration.
NextEra submits that the Commission has ultimate responsibility to
ensure that market rules are just and reasonable, and that the
Commission cannot delegate its responsibility to states, regions, or
public utilities. Tres Amigas requests that the Commission clarify that
intra-hour scheduling will apply to all generation scheduled on the
bulk transmission system; inter- and intra-balancing authority
transactions, and point-to-point, network, or native load service. Tres
Amigas states that inconsistent transmission scheduling periods will
lead to inefficient and/or discriminatory use of the transmission
system.
69. Many commenters contend that the Commission should afford
public utility transmission providers the flexibility to determine how
best to implement intra-hour scheduling in their region. These
commenters ask the Commission to acknowledge that region-specific
scheduling practices may be appropriate in light of system
circumstances and market designs.\94\ Several of these commenters note
that there are regional efforts and pilot programs underway that are
aimed at efficiently managing the integration of VERs and providing an
opportunity for intra-hour scheduling.\95\ These commenters generally
contend that the Commission should support and not undermine such
regional initiatives. Examples of regional initiatives identified by
commenters include the Joint Initiative,\96\ the WECC Efficient
Dispatch Toolkit,\97\ and a pilot between Bonneville Power and the
California ISO to evaluate the use of intra-hour scheduling on the
California-Oregon Intertie.\98\ Several commenters suggest that the
Commission should conduct technical conferences to investigate the
relative merits of these and alternative approaches prior to imposing a
uniform national mandate.\99\
---------------------------------------------------------------------------
\94\ E.g., Avista; Bonneville Power; California ISO; CMUA;
California PUC; Detroit Edison; Dominion; EEI; FirstEnergy; Grant
PUD; Idaho Power; Independent Power Producers Coalition-West; ISO/
RTO Council; Midwest ISO; Montana PSC; National Grid; NorthWestern;
NRECA; New York ISO; NV Energy; PJM; PNW Parties; Public Power
Council; Puget; SMUD; Southern; Tacoma Power; WUTC; WestConnect.
\95\ E.g., Avista; Bonneville Power; Business Council;
California ISO; California PUC; CESA; CMUA; EEI; Idaho Power; Joint
Initiative; Montana PSC; National Grid; NorthWestern; NV Energy; PNW
Parties; Puget; SMUD; WestConnect.
\96\ The Joint Initiative is a consensual, collaborative effort
within the Western Interconnection to develop high-value and cost-
effective regional products, identified through a stakeholder
process, for implementation by interested parties. It is jointly
sponsored by Columbia Grid, Northern Tier Transmission Group, and
WestConnect. Joint Initiative at 1-3. Step one of the Products and
Services Strike Team intra-hour scheduling initiative began in July
2011 with the scheduling of transmission in half hour increments.
Step two includes broader application of intra-hour scheduling and
scheduling in finer increments (15 or 20 minutes) only after
evaluation that this step is necessary.
\97\ The WECC Efficient Dispatch Toolkit contains: (1) An
enhanced curtailment calculator that will aid in managing flows
across constrained paths; and (2) an energy imbalance market that
will efficiently dispatch resources in response to imbalance.
\98\ This pilot program is intended to facilitate the export of
wind resources located in Bonneville Power's Balancing Authority
into the California ISO. The pilot will use dynamic e-tagging and
communication to facilitate intra-hour schedule changes, beginning
with a 30-minute scheduling interval.
\99\ E.g., California ISO; Grays Harbor PUD; Pacific Gas &
Electric; SMUD; Snohomish County PUD.
---------------------------------------------------------------------------
70. Some commenters express concern that a Commission mandate may
detrimentally affect current regional efforts by diverting resources
from or discouraging participation in voluntary regional initiatives by
both jurisdictional and non-jurisdictional entities.\100\ Bonneville
Power and CMUA suggest that ongoing initiatives may provide the
Commission with real-world data and alternative options to reach the
Commission's stated goals. In order to support ongoing regional
initiatives, Pacific Gas & Electric recommends that the Commission not
implement 15-minute scheduling until regional initiatives have been
given a reasonable amount of time to come to an end. Grant PUD argues
that 20-30 minute scheduling intervals appear to be sufficient for the
Northwest region of the country and that the Commission should allow
this to be considered a ``regional practice.'' \101\ In addition, NRECA
argues that the Commission should afford public utility transmission
providers an opportunity to demonstrate that existing practices or
practices under development are or will be consistent with or superior
to the Commission's proposed reforms.
---------------------------------------------------------------------------
\100\ E.g., Avista; Bonneville Power; California PUC; EEI; Idaho
Power; National Grid; NorthWestern; NRECA; NV Energy; PNW Parties.
\101\ Grant PUD at 4.
---------------------------------------------------------------------------
71. Some commenters stress the need for regional flexibility
because, in their view, intra-hour scheduling may not be the right
decision for everyone.\102\ For example, LADWP asserts that the
Proposed Rule is ill-timed, and that intra-hour scheduling may not be
necessary in regions where the existing generation portfolio provides
sufficient flexibility to integrate a fixed percentage of VER
penetration reliably. Southwestern explains that, as a federal agency
operating under a Congressional statutory mandate, the Administration
may not be able to implement intra-hour scheduling as this may impact
the purposes of the Corps projects such as flood control, hydropower,
navigation, fish and wildlife, and recreation. If the Commission adopts
the Proposed Rule, NRECA urges the Commission to permit public utility
transmission providers to seek a waiver from implementing intra-hour
scheduling until the entity receives a request to schedule intra-hour.
---------------------------------------------------------------------------
\102\ E.g., ISO/RTO Council; NorthWestern; Pacific Gas &
Electric; PNW Parties; Public Power Council; Puget.
---------------------------------------------------------------------------
72. A number of commenters question the applicability of the
proposed intra-hour scheduling requirements in regions with RTOs/ISOs,
arguing that these markets already provide for system flexibility that
is consistent with or superior to the intra-hour scheduling protocol
proposed by the Commission.\103\ Business Council suggests that the
Commission should focus its attention on areas where rapid spot energy
and ancillary service markets do not exist, particularly non-RTO/ISO
areas that are experiencing significant renewable energy penetration.
ISO/RTO Council asks the Commission to recognize that different regions
currently provide varying levels of flexibility to VERs through
different
[[Page 41495]]
systems and market mechanisms, suggesting that the Commission craft the
Final Rule in a manner that allows transmission providers to work with
their stakeholders to develop solutions that work for their region.
FirstEnergy asserts that each RTO and ISO, through its stakeholder
process, should be given the opportunity to evaluate the potential need
for, and benefits and costs associated with, intra-hour scheduling.
Sunflower and Mid-Kansas similarly argue that the Final Rule should
recognize the differences between organized markets and not group them
with non-RTO public utility transmission providers. Environmental
Defense Fund asserts that, because some RTOs and/or balancing
authorities have begun to implement regional scheduling reforms, the
Commission should avoid imposing duplicative requirements or
obstructing such efforts.
---------------------------------------------------------------------------
\103\ E.g., AWEA; California ISO; California PUC; Detroit
Edison; Iberdrola; ISO New England; Massachusetts DPU; Midwest ISO;
PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas;
Western Farmers.
---------------------------------------------------------------------------
73. Some commenters suggest that the Commission clarify that its
proposed intra-hour scheduling reforms apply only to RTOs and ISOs in
the context of transactions between balancing authorities.\104\
However, National Grid cautions the Commission against overly-
prescriptive requirements for scheduling between regions and asks for
clarification that public utility transmission providers are permitted
to pursue other scheduling improvements for cross border transactions
and inter-tie scheduling. National Grid notes that New York ISO and ISO
New England are already working on solutions to improve interregional
interchange scheduling. ISO/RTO Council states that accelerated
scheduling changes may negatively affect RTO and ISO interchanges with
non-market areas, as those smaller areas may be unable to keep up with
an RTO or ISO scheduling within the hour.
---------------------------------------------------------------------------
\104\ E.g., AWEA; Iberdrola; Public Interest Organizations; and
RENEW.
---------------------------------------------------------------------------
74. Many commenters express concern regarding the potential for
seams issues, particularly with transmission providers that are not
subject to the Commission's ratemaking jurisdiction under sections 205
and 206 of the FPA.\105\ Some commenters argue that, for a generator to
submit a 15-minute schedule, all balancing authorities involved in the
transmission chain must approve the tag or it will be rejected.\106\
While the source balancing authority may approve the schedule, PNW
Parties explain that the schedule may be denied in the adjacent
balancing area if the same intra-hour scheduling procedures are not
used, irrespective of the jurisdictional status of the transmission
providers involved. Xcel suggests that, in areas where the balancing
authority and transmission provider are separate entities, explicit
guidance may be needed in order for a balancing authority to accept
intra-hour schedules from a transmission provider. Xcel recommends that
the Commission place responsibility on the balancing authority to
approve intra-hour scheduling changes made in accordance with an
approved tariff.
---------------------------------------------------------------------------
\105\ E.g., Avista; California ISO; Duke; EEI; Idaho Power;
MidAmerican; NorthWestern; NV Energy; PNW Parties; Puget; Southern
California Edison; Southern; Tres Amigas; WUTC.
\106\ E.g., PNW Parties; Puget; WUTC.
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75. Additionally, these commenters question how beneficial intra-
hour scheduling will be in the absence of consistent and compatible
scheduling intervals among jurisdictional and non-jurisdictional
entities.\107\ Puget states that, while it has offered intra-hour
scheduling since December 2009, its customers have scheduled few
transactions due to the lack of conforming scheduling practices in
neighboring non-jurisdictional utilities. If transmission customers are
unable to schedule across seams at 15-minute intervals, Puget argues
that jurisdictional utilities will receive little benefit from the
required software, personnel and accounting changes needed to
facilitate 15-minute scheduling. Idaho Power submits that seams issues
created by different intervals in adjacent systems may ultimately lead
to an increase in the costs of VER integration. WUTC asserts that for
jurisdictional entities to implement intra-hour scheduling unilaterally
would be economically unproductive and may disrupt reliability
functions. Idaho Power and EEI similarly contend that seams issues may
affect reliability.
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\107\ E.g., Avista; California ISO; Duke; EEI; Idaho Power;
NorthWestern; NV Energy; PNW Parties; Puget; Southern California
Edison; Southern; Tres Amigas; WUTC.
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76. EEI suggests that the Commission not require public utility
transmission providers to provide intra-hour scheduling prior to an
evaluation of the impacts on coordination between and among
jurisdictional and non-jurisdictional entities. California ISO contends
the parties in the West should continue with coordinated efforts to
find reasonable solutions that can be implemented without placing an
undue burden on neighboring parties. California PUC recommends that the
Commission allow sufficient flexibility for public utility transmission
providers to determine the most efficient way to support intra-hour
scheduling across interties.
77. Snohomish County PUD and Grays Harbor PUD request that the
Commission evaluate whether existing supply arrangements with
Bonneville Power, referred to as ``slice'' contracts, allow for intra-
hour scheduling before adopting the proposed requirements. Snohomish
County PUD explains that these contracts allow customers to pay a fixed
percentage of Bonneville Power's costs and, in turn, receive an equal
percentage of output, thereby taking advantage of the flexibility of
the federal system. However, Snohomish County PUD and Grays Harbor PUD
state that these ``slice'' contracts limit customers to hourly
scheduling. Snohomish County PUD is concerned that it and other
similarly situated transmission providers may be unable to implement
15-minute scheduling. Snohomish County PUD contends that, as a result,
it and others may have to acquire additional reserves in order to
balance wind resources, in effect paying twice for the same capacity
and scheduling flexibility. Snohomish County PUD asserts that this
issue has already arisen in Bonneville Power's ongoing efforts to
develop intra-hour scheduling at 30-minute intervals.
iii. Cost to Implement Intra-Hour Scheduling
78. A number of parties address the potential costs of implementing
the Commission's proposed intra-hour scheduling requirement. Exelon
states that there likely will be some development and ongoing
administrative costs, such as modifying Open Access Same-Time
Information System (OASIS) and interchange ramp software and additional
staff to evaluate and confirm more frequent scheduling changes, but
does not expect that such costs would be excessive. Tres Amigas
contends that the incremental costs of providing intra-hour scheduling
will be very modest. NaturEner argues that many transmission providers
could implement intra-hour scheduling with existing staff and equipment
but that, even if that is not the case, entities should be incentivized
or required to automate or otherwise update their system as it would
expedite the scheduling and transmission approval system. Independent
Power Producers Coalition-West contends that increased automation and
staffing would enhance the ability of a balancing authority to schedule
at shorter intervals and achieve further integration of VERs.
79. Other commenters state that the cost of implementing intra-hour
[[Page 41496]]
scheduling may be significant.\108\ EEI and PNW Parties assert that
intra-hour scheduling will affect many activities and systems, causing
transmission providers in some regions to institute hardware, software,
and personnel changes. For example, EEI and PNW Parties contend that
changes will be required to numerous computer systems, such as energy
management systems, scheduling applications, and automated checkout
systems such as the WECC Interchange Tool, and also that certain
practices not currently automated will have to be automated. EEI and
PNW Parties note that staff would need to be trained on these new tools
and additional staff would be required to process the expanded
scheduling information being received. NRECA contends that the costs
will be driven largely by software and personnel changes, rather than
hardware investments, but that it is difficult to estimate with
precision what software changes would be needed without knowing what
measures NAESB will adopt in order to standardize the new scheduling
regime.
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\108\ E.g., Avista; Bonneville Power; EEI; Grant PUD;
MidAmerican; NRECA; NorthWestern; PNW Parties; Puget; Snohomish PUD;
Southern California Edison; Southwestern; Tacoma Power; TVA.
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80. NextEra explains that several steps will need to be taken in
order to implement 15-minute scheduling but contends that the cost
impacts are uncertain. NextEra provides that actions to implement
intra-hour scheduling include potential modifications to both internal
and external software packages. According to NextEra, these software
programs, providing functions such as eTagging, accounting, and
billing, will need to be harmonized across vendors. Additionally,
NextEra contends that it is unclear whether existing systems would need
to be replaced or modified, or whether functions currently being
performed manually would need to be automated.
81. Some transmission providers estimate the level of investment
and staffing changes that would be required to implement 15-minute
scheduling on their system, although most discuss such estimates in the
context of a broader range of activities that they believe may be
intended or implicated by the implementation of 15-minute
scheduling.\109\ For example, Avista states that it would need to hire
and train around-the-clock personnel at an estimated cost of $1.2
million per year to implement ``an approach that will allow for
schedule adjustments and imbalance settlements in 15 minute periods.''
\110\ MidAmerican estimates approximately $1.0 million in staff costs
to implement ``similar intervals for balancing activities and
interchange'' and, to the extent energy management and accounting
systems must be changed, up to $2.0-2.3 million in infrastructure
upgrades.\111\ Bonneville Power also contends that it would need an
additional 24x7 position, staffed by six full-time employees, to manage
what it characterizes as the risks created by 15-minute scheduling,
including the redesign of imbalance service and increased use of
special protection schemes.
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\109\ E.g., Avista; Bonneville Power; Grant PUD; MidAmerican;
NorthWestern; PNW Parties; Puget; Snohomish County PUD;
Southwestern; Tacoma Power; TVA.
\110\ Avista at 12, 14 (emphasis in original).
\111\ MidAmerican at 14.
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82. NRECA notes that the relative cost impact of implementing
intra-hour scheduling will depend on a number of factors, such as the
size of the system and how widely intra-hour scheduling is utilized.
Although agreeing that the costs may be significant, NRECA states that
costs are not expected to be extraordinary and can be mitigated through
proper design and implementation. NRECA estimates implementation costs
under a range of scenarios. Assuming hourly schedules at a 15-minute
interval used only by VERs, NRECA anticipates the need for software
modifications in the range of $50,000 per company, but notes that some
of its members have incurred expenses in the range of $250,000 annually
for software licensing and maintenance related to scheduling and energy
accounting software upgrades. If hourly schedules at a 15-minute
interval are widely used by transmission customers, NRECA estimates a
minimum of one additional 24x7 shift, resulting in approximately $1.0
million of staffing costs, and potentially two 24x7 positions depending
on the size of the transmission provider. Finally, if hourly schedules
at a 15-minute interval are settled on a 15-minute basis, NRECA
estimates an additional $250,000 to $300,000 for additional ``back
room'' staff to settle 15-minute schedules, interchange and deviation
accounts.
83. Bonneville Power contends that many of the short-term costs
associated with 15-minute scheduling would not be incurred to implement
scheduling on 30-minute intervals. Bonneville Power states that it is
currently updating systems and work processes to implement 30-minute
scheduling in association with regional initiatives and that it
believes the changes, resources, and system impacts associated with the
implementation of scheduling at a 30-minute interval will be relatively
modest compared to what would be required to implement 15-minute
scheduling. Bonneville Power asserts that the systems, transmission
upgrades, and resources required to accommodate the increasingly
dynamic movements of power across the interconnection under 15-minute
scheduling would not be required under 30-minute scheduling. Tacoma
Power argues that it will determine the level of automation needed for
30-minute scheduling based on the experience it gains during
implementation of the Joint Initiative intra-hour program, but that
implementation of 15-minute scheduling intervals as discussed in the
Proposed Rule would require immediate automation of all the processes
for Tacoma Power to have any market presence.
iv. Requests for Additional Requirements
84. Some commenters contend that transmission customers should be
encouraged or required to submit intra-hour schedules, arguing that the
Commission's objectives of lowering reserve costs can be reached only
if intra-hour scheduling is utilized in a consistent and predictable
manner.\112\ Bonneville Power argues that mandatory intra-hour
scheduling is necessary to achieve the reduction in reserve
requirements of 80 percent cited in its 2008 study.\113\ Idaho Power
and PNW Parties contend that VERs generally have a strong financial
incentive to maximize energy output and, therefore, may schedule for a
full hour to maximize benefits regardless of the availability of 15-
minute scheduling. WUTC recommends that the Commission couple the
implementation of intra-hour scheduling with measures to mitigate over-
scheduling by VERs, particularly when market conditions are favorable
for over-scheduling.
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\112\ E.g., Bonneville Power; EEI; Idaho Power; MidAmerican;
NorthWestern; Puget; PNW Parties; WUTC.
\113\ Bonneville Power (citing Bart McManus, Large Wind
Integration Challenges and Solutions for Operations/System
Reliability (2008). Bonneville Power clarifies that, in the study,
mandatory 10-minute scheduling on a 10-minute persistence basis
reduced the reserve requirements in the BPA region by 80 percent.
Bonneville Power also clarifies that this reduction only applies to
the source Balancing Authority, not the sink Balancing Authority).
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85. Others recommend that the Commission provide incentives to use
intra-hour scheduling by eliminating the exemption of VERs from third-
tier generator imbalance penalties in Schedule 9 of the pro forma OATT,
which they argue would no longer be just and reasonable given the
[[Page 41497]]
Commission's proposed reforms.\114\ In addition to eliminating the
exemption from third-tier generation imbalance penalties, MidAmerican
suggests that an additional imbalance penalty tier be created for any
transmission customer that consistently fails to adjust schedules on an
intra-hour basis and creates significant variability. Avista recommends
that the Commission allow transmission providers to impose appropriate
penalties and recover the true costs of providing intra-hour schedules
from VERs that continue to schedule on an hourly basis.
---------------------------------------------------------------------------
\114\ E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.
---------------------------------------------------------------------------
86. Several commenters argue that intra-hour scheduling may not
achieve its intended benefits without additional reforms to augment
intra-hour scheduling practices.\115\ Some of these commenters assert
that the Commission should allow a public utility transmission provider
the flexibility to revise its energy imbalance settlement periods to
align with any intra-hour scheduling interval.\116\ Southern contends
that this will allow a public utility transmission provider to offer
appropriate incentives to customers to follow a given schedule and
limit the potential for exposure to uncompensated risks.
---------------------------------------------------------------------------
\115\ E.g., Avista; AWEA; RenewElec; Vote Solar.
\116\ E.g., EEI; Duke; Idaho Power; Southern.
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87. However, Avista states that there are positives and negatives
to either maintaining hourly settlement with intra-hour scheduling or
modifying settlement intervals to coincide with intra-hour scheduling
intervals. Avista asserts that conforming intra-hour schedules and
imbalance settlement at 15-minute increments for all transmission
schedules would result in alignment of scheduling and imbalance billing
for all transactions and reduce gaming potential. Avista argues that
the potential for gaming by transmission customers through the
overcorrection of schedules in order to minimize imbalance charges may
require a public utility transmission provider to carry regulation
reserves in excess of what is needed. Midwest ISO agrees, citing a
report from its Independent Market Monitor indicating that large
changes in Net Scheduled Interchange caused by 15-minute intra-hour
scheduling could lead to price volatility and negative operational
impacts.\117\ Avista and Midwest ISO further state that conforming
imbalance settlement with intra-hour schedules may require substantial
and potentially costly office system changes, additional operations
staff, and other costs incurred through the communication, metering,
and storage of all customer data at 15-minute increments.
---------------------------------------------------------------------------
\117\ Midwest ISO (Potomac Economics, 2008 State of the Market
Report for the Midwest ISO, Docket No. ZZ09-4-000 at 169 [141] (June
21, 2009)).
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88. Some commenters contend that intra-hour scheduling only governs
the scheduling of flows on the transmission system and, by itself, does
not necessarily affect the frequency with which generators are
dispatched.\118\ AWEA and Invenergy Wind agree that a transition to
sub-hourly dispatch is the key for increasing the flexibility of the
power system and for reducing the amount of reserves that must be held,
which in turn will reduce costs for consumers and enable cost effective
integration of VERs. Commenters recommend that the Commission require
public utility transmission providers to implement a sub-hourly, real-
time energy exchange that provides automated generation dispatch (such
as an Efficient Dispatch Toolkit or the Energy Imbalance Market as
adopted by the Southwest Power Pool and currently being studied in
WECC). In AWEA's view, a market for sub-hourly energy would allow for
netting of sub-hourly deviations and would provide price signals to
incent greater sub-hourly flexibility.
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\118\ E.g., AWEA; CEERT; Invenergy Wind.
---------------------------------------------------------------------------
89. AWEA acknowledges that changes to dispatch protocols and
expansion of market options are being considered in regional efforts,
but argues that progress is uncertain and unlikely to come to fruition
in the near term. Iberdrola argues that intra-hour scheduling must be
combined with intra-hour dispatch or market purchases to achieve the
Commission's goals. Oregon and New Mexico PUC recommend that the
Commission encourage reforms such as an Energy Imbalance Market or 15-
minute calculations of available transmission capability (ATC) as a
complement to intra-hour scheduling. However, Bonneville Power suggests
distinguishing between intra-hour scheduling outside of a market region
and intra-hour dispatch in an organized market, arguing that the costs
and benefits of each may be dramatically different. Bonneville Power
explains that the resources devoted to implementing 15-minute
scheduling may be better used to pursue the development of an organized
market with frequent dispatch intervals.
90. Some commenters assert that the Commission should consider
changes to other aspects of electricity markets to facilitate intra-
hour scheduling.\119\ Invenergy Wind contends that consistent
timeframes across all transmission and generation functions may lead to
more efficient use of transmission capacity, regulation, and other
ancillary services. American Clean Skies explains that the technology
necessary to schedule transmission in 15-minute increments will also
allow for scheduling reforms in the day-ahead market and the unit
commitment process and, therefore, the Commission should require 15-
minute scheduling reforms in these areas as well. However, PJM asserts
that real-time control issues do not exist day-ahead and, therefore,
the Commission need not consider reforms to the day-ahead market.
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\119\ E.g., American Clean Skies; Invenergy Wind.
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c. Commission Determination
91. The Commission concludes that it is appropriate to act at this
time to adopt the scheduling reforms set forth in the Proposed Rule.
Specifically, the Commission amends the pro forma OATT to provide all
transmission customers the option of using more frequent transmission
scheduling intervals within each operating hour, at 15-minute
intervals. Our actions in this Final Rule will ensure that charges for
generator imbalance service under Schedule 9 of the pro forma OATT and
for other ancillary services through which reserve-related costs are
recovered are just and reasonable and are not unduly
discriminatory.\120\
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\120\ In section IV.C (Generator Regulation Service Capacity)
infra, the Commission acknowledges that a range of capacity services
could be used by public utility transmission providers to recover
reserve-related costs.
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92. As noted in the Proposed Rule, many pro forma OATT
requirements, including hourly scheduling protocols, were developed at
a time when virtually all generation on the system could be scheduled
with relative precision.\121\ As part of the Commission's regulatory
responsibilities, we routinely review and, where appropriate, implement
reforms to ensure the provision of service that remains just and
reasonable and not unduly discriminatory. A similar review led the
Commission in Order No. 890 to exempt VERs from the third-tier of
generator imbalance penalties, given that VERs have a limited ability
to accurately follow an hourly transmission schedule and, as a result,
exposure to high imbalance penalties does not lessen their incentive to
deviate from their schedule.\122\ In this Final Rule, we take an
additional step to allow transmission customers the flexibility to
adjust their transmission
[[Page 41498]]
schedules, in advance of real-time, to reflect the variability of
output in generation, more accurate power production forecasts to
predict output, and other changes in load profiles and system
conditions.
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\121\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 38.
\122\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 665.
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93. Specifically, the Commission affirms the preliminary finding in
the Proposed Rule that existing hourly scheduling protocols expose
transmission customers to excessive or unduly discriminatory generator
imbalance charges.\123\ Under Schedule 9 of the pro forma OATT,
generator imbalance charges are assessed on deviations between
generator output and a delivery schedule over a single hour.\124\ There
is no requirement to provide customers the opportunity to adjust their
transmission schedules within the hour to reflect changes in generator
output. As a result, transmission customers have no ability under the
pro forma OATT to mitigate Schedule 9 generator imbalance charges in
situations when the transmission customer knows or believes that
generation output will change within the hour. The Commission concludes
that this lack of ability to update transmission schedules within the
hour can cause charges for Schedule 9 generator imbalance service to be
unjust and unreasonable or unduly discriminatory. As a result of the
intra-hour scheduling reforms of this Final Rule, the metric against
which generator imbalances are measured will be more granular than
under current hourly scheduling protocols.
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\123\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 37.
\124\ Imbalance charges are calculated by multiplying the
quantity of imbalance by a set percentage of incremental or
decremental costs defined in three deviation bands. These charges
are netted on a monthy basis and settled financially at the end of
each month. For example, any deviations greater than
7.5 percent (or 10 MW) of the scheduled transaction (applied hourly)
will be settled at 125 percent of incremental costs or 75 percent of
decremental costs. See OATT Schedule 9.
---------------------------------------------------------------------------
94. The Commission expects that many types of entities, not only
VERs, may benefit from the availability of intra-hour scheduling. Every
transmission customer will have the ability to adjust its schedule at
15-minute intervals to reflect changing conditions. This includes, for
example, transmission customers that experience a within-hour forced
outage or transmission customers taking delivery from energy
constrained resources (such as flow-limited hydro-electric generators,
emission-limited thermal generators, and energy storage resources),
even if using point-to-point transmission internal to the system. For
example, we note that Entergy voluntarily adopted intra-hour
transmission scheduling without the presence of substantial VERs in an
effort to manage fluctuations in output from qualifying facilities on
its system.\125\ Based on this experience and the record in this
proceeding, the Commission finds that intra-hour scheduling will
provide a range of transmission customers with a necessary tool to
mitigate exposure to Schedule 9 generator imbalance charges in light of
changing conditions.
---------------------------------------------------------------------------
\125\ See Entergy Serv. Inc., 111 FERC ] 61,314 (2005).
---------------------------------------------------------------------------
95. The Commission also finds that, over time, implementation of
intra-hour scheduling will allow public utility transmission providers
to rely more on planned scheduling and dispatch procedures, and less on
reserves, to maintain overall system balance. Under hourly scheduling
protocols, the source balancing authority for a transaction is required
to honor its transmission schedule across an entire hour, requiring the
source balancing authority to have sufficient reserves in place to
manage imbalances within the hour, i.e., maintain consistent delivery
of the scheduled amount of energy to the sink balancing authority over
the hour. This includes reserves to respond to variations in generation
output that are moment-to-moment as well as longer-term, but occurring
within the hour, represented by the solid line in Figure 1.
[[Page 41499]]
[GRAPHIC] [TIFF OMITTED] TR13JY12.000
96. By moving from hourly to 15-minute scheduling intervals, the
amount of imbalance energy for which the source balancing authority is
potentially responsible can be reduced, as reflected in Figure 1. This
can lead to a corresponding reduction in the amount of capacity held to
provide that energy and, in turn, lower reserve-related costs for the
source balancing authority, and ultimately consumers. Therefore, the
Commission also finds that implementation of intra-hour schedules is
necessary in order to ensure that charges for ancillary services
through which reserve-related costs are recovered are just and
reasonable and not unduly discriminatory.\126\
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\126\ One mechanism that could be used to recover reserve-
related costs is generator regulation service. The Commission
provides guidance regarding the development of generation regulation
charges in section IV.C.2 (Mechanics of Generator Regulation Charge)
infra. Among other things, public utility transmission providers
should consider the extent to which transmission customers are using
intra-hour scheduling in evaluating whether to require different
transmission customers to provide or otherwise account for different
quantities of generator regulation service.
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97. For these reasons, the Commission adopts the proposal set forth
in the Proposed Rule and directs public utility transmission providers,
consistent with the compliance deadlines addressed below, to revise
their OATTs to provide an opportunity for transmission customers to
submit transmission schedules at 15-minute intervals. In response to
Bonneville Power and Xcel, the Commission clarifies that this
requirement is intended to allow transmission customers to both modify
existing schedules as well as create new schedules, provided that the
transmission customer has a transmission reservation in place.\127\ The
ability to create new transmission schedules within the hour will be
particularly important to resources that may seek to provide intra-hour
energy products, as discussed further below.
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\127\ To be clear, this Final Rule does not alter the
transmission products of the pro forma OATT and, therefore,
implementation of intra-hour scheduling does not require (yet would
not preclude) the intra-hour calculation of ATC or sale of
transmission service.
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98. The Commission notes that most commenters support the practice
of intra-hour scheduling, with disagreement focused primarily on the
frequency of schedule adjustments and whether changes to existing
scheduling should be paired with other reforms. Balancing the competing
considerations raised by commenters, the Commission concludes that a
15-minute scheduling interval is appropriate and declines to impose
additional reforms at this time. The Commission appreciates that
implementation of other reforms, such as intra-hour imbalance
settlement, an intra-hour transmission product, increasing the
frequency of resource commitment through sub-hourly dispatch, or the
formation of intra-hour imbalance markets, could yield additional
benefits for public utility transmission providers and their customers.
However, these additional reforms can have significant costs. The
Commission's review of the record in this proceeding suggests that a
more measured approach is appropriate to take at this time.\128\
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\128\ As noted below, public utility transmission providers will
have an opportunity on compliance to demonstrate that alternative
intra-hour scheduling proposals are consistent with or superior to
the intra-hour scheduling requirements of this Final Rule. Such a
proposal could include one or more of the additional reforms
requested by commenters, such as the formation of intra-hour
imbalance markets.
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99. The Commission acknowledges that implementation of intra-hour
scheduling can result in a shift of responsibility for holding certain
reserves away from the source balancing
[[Page 41500]]
authority for export transactions.\129\ As explained above, allowing
for more granular transmission schedules can reduce the amount of
variation in generation output for which the source balancing authority
is responsible. The Commission appreciates that, from the sink
balancing authority's perspective, scheduling at shorter intervals may
result in the purchaser of energy having to manage more frequent
changes in scheduled deliveries as compared to scheduling at hourly
intervals. As indicated in Figure 2, a purchaser under existing hourly
scheduling protocols receives a fixed quantity of energy over the hour
from the source balancing authority, whereas use of 15-minute intervals
could result in fluctuating deliveries across the hour.
---------------------------------------------------------------------------
\129\ E.g., Xcel; Iberdrola.
[GRAPHIC] [TIFF OMITTED] TR13JY12.001
To the extent the purchaser desires to continue receiving a
constant delivery of energy across the hour, represented by the dotted
line in Figure 2, it may be required to obtain that energy from the
market.\130\ The Commission concludes that this is an appropriate
division of responsibility, as opposed to the current hourly system
which places all responsibility for managing variations in generation
output across the hour solely on the source balancing authority. Within
the hour, the source balancing authority retains its responsibility of
providing the energy needed for the VER to meet its schedule, while the
purchaser takes on the responsibility of managing more frequent
deliveries of scheduled energy.
---------------------------------------------------------------------------
\130\ For example, sellers of VER energy could have existing
contractual commitments to deliver at constant volumes over
specified periods.
---------------------------------------------------------------------------
100. By shifting responsibility for managing certain variations in
generation output to the purchasing entity, purchasing entities will
have greater incentive to manage changes in scheduled deliveries from
15-minute interval to 15-minute interval and the portfolio of resources
that ultimately manage total VER variability will likely be more cost-
effective than under current practices. Specifically, a portfolio of
resources that respond over a range of time scales, from very fast to
relatively slow, is lower cost than a portfolio that relies on
resources designed to manage only the short-run variability of
VERs.\131\ For instance, portfolio cost savings could result from using
a combination of expensive resources with automated generator control
and less expensive resources that provide following service rather than
using only resources with automated generator control. While the source
balancing area could choose to manage VER variability with a portfolio
of resources that respond over a range of time, it has little incentive
to do so because any additional costs can be recovered from
transmission customers. We expect use of a portfolio of resources to
lower the overall cost of managing VER variability. The Commission
anticipates that buyers and sellers also may respond by developing
intra-hour balancing products. EPSA notes that the additional market
liquidity created by the ability to schedule transmission intra-hourly
can provide opportunities for existing resources to manage system
[[Page 41501]]
variability by offering within-hour energy products. This is equally
true for market participants seeking to maximize the value of their
resources, or lower their purchased power costs, through intra-hour
trading. As the liquidity of intra-hour energy products stabilizes,
market participants also may begin to commit or otherwise acquire fewer
reserves in advance, with the knowledge that they can purchase
additional reserves on an as-needed basis from third parties. Requiring
public utility transmission providers to offer intra-hour scheduling is
a necessary predicate to facilitate these market opportunities.\132\
---------------------------------------------------------------------------
\131\ See e.g., J. Apt, The Spectrum of Power from Wind
Turbines. Journal of Power Sources, Vol. 169, No. 2, at 369-374
(2007); cited at RenewElec comments at note 4.
\132\ For example, the Joint Initiative has implemented an
electronic platform to facilitate bilateral intra-hour transactions,
the Intra-hour Transaction Accelerator Platform (I-TAP), also
referred to as the WebExchange. See http://www.columbiagrid.org/itap-overview.cfm.
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101. Notwithstanding broad support in comments for some version of
intra-hour scheduling, as noted above, there was significant
disagreement in the comments as to the appropriate time interval. Some
commenters supported the 15-minute interval proposed by the
Commission,\133\ while others argued for either shorter (e.g., 5-
minute) or longer (e.g., 30-minute) scheduling intervals.\134\ In
evaluating these comments, the Commission has balanced the competing
interests of allowing transmission customers to more closely match
schedules with anticipated generation output against not unduly
burdening public utility transmission providers in implementing the
intra-hour scheduling reform. The Commission concludes that adoption of
a 15-minute scheduling interval for purposes of the pro forma OATT is
reasonable. In its comments on the NOI, NERC states that the ideal
scheduling increment would be between 5 and 15 minutes depending on
system characteristics.\135\ NERC reasoned that, while balancing
authorities that schedule energy transactions on an hourly basis may
have sufficient regulation resources to maintain the schedule for the
hour, reducing scheduling intervals to ten minutes, for example, could
make economically dispatchable generators in an adjacent balancing
authority available to provide necessary ramping capability through an
interconnection.\136\ The Commission agrees and, as discussed above,
anticipates that the availability of intra-hour scheduling at 15-minute
intervals will facilitate the development of ramping products to manage
variability in generation output more effectively. For these reasons we
adopt 15-minute transmission scheduling as proposed.
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\133\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP
Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC;
Defenders of Wildlife; EPSA; Exelon; First Wind; Independent Energy
Producers; NaturEner; Organization of Midwest ISO States; Oregon &
New Mexico PUC; Powerex; Public Interest Organizations; SWEA; Tres
Amigas; Viridity Energy; Western Grid; Xcel.
\134\ Compare Environmental Defense Fund; FriiPower; Independent
Power Producers Coalition-West; RenewElec; SEIA; Vestas; and Vote
Solar (advocates of shorter) with Bonneville Power; California PUC;
CMUA; Montana PSC; NorthWestern; Puget; Snohomish County PUD;
Southern California Edison; WUTC (advocates of longer).
\135\ NERC April 12, 2010 Response to NOI (NERC NOI Comments).
\136\ NERC NOI Comments.
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102. In adopting a 15-minute transmission scheduling interval, we
recognize that the cost of moving from hourly to 15-minute transmission
scheduling could be substantial. Several transmission providers state
that costs will depend heavily on the extent to which intra-hour
scheduling is actually used by transmission customers, estimating
staffing costs to be in the range of $1-2 million per year if widely
used.\137\ While these costs are not insignificant, greater use of
intra-hour schedules means that more transmission customers are
mitigating exposure to Schedule 9 generator imbalance charges and
providing greater opportunities for public utility transmission
providers to lower reserve-related costs. Commenters generally agree
that the cost of implementing intra-hour scheduling will correlate to
usage, with lower costs in those systems with fewer intra-hour
schedules. In contrast, substantial use of intra-hour scheduling would
affirm the usefulness of the option for transmission customers,
justifying the added expense of processing a larger number of
transmission schedules.
---------------------------------------------------------------------------
\137\ E.g., Avista; NRECA. To the extent intra-hour scheduling
is not widely used by transmission customers, NRECA states its
members likely could implement scheduling at 15-minute intervals
with software modifications in the range of $50,000 per company,
without additional staffing requirements.
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103. Many of the costs cited by commenters as being specific to 15-
minute scheduling are related to the automation of systems used to
process transmission schedules and verify cross-balancing authority
aggregate schedules. The Commission notes that it is not mandating
automation of scheduling practices, although we expect that each public
utility transmission provider will consider whether automation of
certain aspects of its system are necessary to implement scheduling at
15-minute intervals. To the extent a public utility transmission
provider automates scheduling processes in response to increased
scheduling activity, the Commission agrees with NaturEner and
Independent Power Producers Coalition-West that automation of these
processes represents a secondary benefit of our transmission scheduling
reform. Several Commission staff audits have uncovered errors related
to manual processing of transmission schedules.\138\ These errors
resulted in a transmission customer submitting a transmission schedule
that resulted in a higher curtailment priority than the underlying
transmission service reservation provided, allowed use of firm network
service to deliver energy from resources that were not designated
resources and allowed use of network transmission service to deliver a
sale to a third party. As a result of these errors, the transmission
customer may have gained access to transmission service that was not
otherwise available, may have inappropriately gained additional
protection from curtailment, and avoided payment for point-to-point
transmission service. Increased automation of schedule process can
reduce such errors and, in turn, ensure that the provision of
transmission service is consistent with the pro forma OATT.
---------------------------------------------------------------------------
\138\ E.g., Puget Sound Energy, Docket No. PA07-1-000 at 25-27;
MidAmerican Energy Co., Audit Report, 112 FERC ] 61,346 at PP 30-34
(2005); and Public Service Company of Colorado, Docket No. PA05-1-
000 at 9-11.
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104. Some commenters raising concerns regarding the cost of
implementing intra-hour scheduling imply that the proposed scheduling
reforms would require changes in settlement procedures for imbalance
service or the frequency of resource commitment through sub-hourly
dispatch, which they state would require significant investments. For
example, EEI and PNW Parties caution that these additional activities
would affect computer systems, such as energy management and accounting
systems.\139\ MidAmerican estimates that upgrading such systems would
cost $2.0-2.3 million. Other commenters, however, encourage the
Commission to require intra-hour imbalance settlement and sub-hourly
dispatch in order to align intra-hour scheduling with financial
settlements and resource commitment. The Commission clarifies that the
requirements of this Final Rule apply to scheduling practices, not
imbalance settlement or sub-hourly dispatch. Public utility
transmission providers may continue to calculate pro forma Schedule 9
generator imbalance charges on an hourly basis under the pro forma
[[Page 41502]]
OATT and rely on hourly resource commitment practices.\140\
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\139\ Eg., EEI; PNW Parties.
\140\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 722;
Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 325 & n.117.
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105. Notwithstanding the continued ability of public utility
transmission providers to rely on hourly calculation of Schedule 9
generator imbalances, as a result of the intra-hour scheduling reforms
of this Final Rule, the metric against which generator imbalances are
measured will be more granular than under current hourly scheduling
protocols. To the extent a public utility transmission provider
believes that aligning the imbalance settlement with the intra-hour
scheduling interval or implementing sub-hourly dispatch will result in
more efficient operations, provide appropriate price signals to
customers, or address other potential issues, it may seek any
authorizations necessary from the Commission to do so under section 205
of the FPA.\141\ Such proposals could be submitted contemporaneously
with the compliance filing in response to this Final Rule or at such
other time the public utility transmission provider believes
appropriate.
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\141\ For example, PNW Parties and Idaho Power note that the
financial incentives some transmission customers have to maximize
output over an hour may in some instances counteract financial
incentives to adjust transmission schedules on a 15-minute basis.
---------------------------------------------------------------------------
106. Several commenters request that the Commission allow for
regional variation in scheduling protocols.\142\ In the Western
Interconnection, many public utility transmission providers already
have implemented some form of intra-hour scheduling at 30-minute
intervals as part of an effort to enhance the operation of bilateral
markets in the Western Interconnection.\143\ Other tools recently
implemented in the West include the I-TAP electronic platform to
schedule energy and request transmission, the Dynamic Scheduling System
to facilitate dynamic scheduling,\144\ and the ACE Diversity
Interchange Program to allow netting of momentary imbalances across
participating balancing authority footprints.\145\ Public utility
transmission providers, state regulators, and others in the West are
studying the impact of these recent initiatives, as well as the
potential benefits and costs of pursuing additional market enhancements
in the future, such as formation of an energy imbalance market. The
Commission acknowledges that future market enhancements in addition to
existing 30-minute scheduling practices and the above-referenced tools,
might yield equivalent or greater benefits to transmission customers
and public utility transmission providers when compared to reducing the
scheduling interval from 30 to 15 minutes and therefore could be
consistent with or superior to the Final Rule's intra-hour scheduling
requirements.
---------------------------------------------------------------------------
\142\ E.g., Avista; Bonneville Power; California ISO; CESA;
CMUA; California PUC; Detroit Edison; EEI; FirstEnergy; Grant PUD;
Idaho Power; Independent Power Producers Coalition-West; ISO/RTO
Council; Midwest ISO; National Grid; Northwestern; NRECA; New York
ISO; NV Energy; Pacific Gas & Electric; PJM; PNW Parties; Public
Power Council; Puget; SMUD; Tacoma Power; WUTC; and WestConnect.
\143\ See e.g., Arizona Public Service Co., 137 FERC ] 61,023
(2011), NorthWestern Corp., 136 FERC ] 61,119 (2011).
\144\ See Joint Initiative.
\145\ See NERC, DRAFT Reliability Guideline: ACE Diversity
Interchange (June 2012), available at http://www.nerc.com/docs/oc/rs/Draft%20ADI%20Reliability%20Guideline%20-%20V1%20060112.pdf.
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107. The Commission therefore affirms the ability of public utility
transmission providers to submit alternative proposals that are
consistent with or superior to the intra-hour scheduling requirements
of this Final Rule and are otherwise just and reasonable and not unduly
discriminatory or preferential.\146\ To make such a showing, a public
utility transmission provider must demonstrate in its compliance filing
how its proposal provides equivalent or greater opportunities for
transmission customers to mitigate Schedule 9 generator imbalance
charges, and for the public utility transmission provider to lower its
reserve-related costs, when compared to implementation of the intra-
hour scheduling requirements of this Final Rule under market practices
currently in place within the region, including tools referenced above
that already have been implemented in the West.\147\ The public utility
transmission provider must include in its compliance filing the tariff
provisions necessary to implement its proposal, including the interval
at which transmission customers may submit transmission schedules. The
public utility transmission provider also must address how its proposed
scheduling interval is consistent with other scheduling practices
within its region. Finally, in recognition that implementation of
intra-hour scheduling can result in a shift of responsibility for
holding certain reserves away from the source balancing authority for
export transactions, public utility transmission providers may consider
the extent to which alternative proposals result in savings to
transmission customers across multiple public utility transmission
provider systems when making the demonstration required above.
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\146\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,770
(permitting public utility transmission providers to propose tariff
modifications that are consistent with or superior to the
requirements of the pro forma OATT).
\147\ To the extent such an alternative proposal includes a
commitment to develop and implement additional market enhancements
in the future, the public utility transmission provider must provide
in its compliance filing: A commitment by senior management to
develop and implement the proposal; a description of collaborative
efforts to date and timeline for future efforts in support of
developing the proposal; and, the date by which the proposed market
enhancement will be implemented.
---------------------------------------------------------------------------
108. Turning to other issues raised by commenters, the Commission
is not convinced by arguments that the current exemption from third-
tier generator imbalance penalties for intermittent resources should be
eliminated to create an incentive for VERs to take advantage of the
option to update transmission schedules every 15 minutes.\148\ In Order
No. 890, the Commission found intermittent generators cannot always
accurately follow their schedules and that high penalties will not
lessen the incentive to deviate from their schedules.\149\ While the
implementation of 15-minute scheduling provides an opportunity for VERs
to better align transmission schedules with actual generation, the
Commission continues to believe that third-tier generator imbalance
penalties are unduly punitive for VERs given their relative inability
to accurately follow schedules whether submitted on an hourly or 15-
minute interval. The Commission concludes that the ability to avoid
penalties in the first two tiers of generator imbalance charges will
provide a sufficient incentive for VERs to adjust transmission
schedules, to the extent they believe such adjustments will mitigate
exposure to Schedule 9 generator imbalance charges. If a public utility
transmission provider believes it necessary to address intentional
deviations, it may propose revisions to Schedule 9 generator imbalance
service pursuant to section 205 of the FPA.\150\ Such proposals would
need to demonstrate that VERs are not adjusting their transmission
schedules despite their reasonable ability to foresee that
[[Page 41503]]
output will deviate significantly from existing transmission
schedules.\151\
---------------------------------------------------------------------------
\148\ E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.
\149\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 665.
\150\ Cf. id. P 676 (noting the ability of public utility
transmission providers to propose additional imbalance penalties for
intentional deviations). Alternatively, the public utility
transmission provider may propose alternative designs for other
ancillary services rates to, for example, offer lower rates to those
transmission customers committing to use intra-hour scheduling.
\151\ The Commission notes that there is a relationship between
a public utility transmission provider's potential need for
alternative imbalance charge structures and the period used for
imbalance settlements. Reinstating third-tier imbalance penalties in
combination with shortened imbalance settlements would more likely
punish VERs for variability that they cannot control, contrary to
the exemption granted in Order No. 890 and affirmed here.
---------------------------------------------------------------------------
109. The Commission acknowledges comments made by some,
particularly in the Pacific Northwest, asserting that the benefits of
intra-hour scheduling will not be fully realized if non-jurisdictional
entities do not adopt a consistent scheduling interval.\152\ However,
the Commission does not believe that limitations in our ratemaking
jurisdiction over non-public utilities should stop us from moving ahead
with reforms applicable to public utilities simply because the impact
of those reforms might be more significant with participation by all
entities. As explained above, requiring all public utility transmission
providers to offer 15-minute transmission scheduling will enable public
utility transmission providers and their customers to manage system
variability more effectively. Therefore, the Commission is hopeful that
non-jurisdictional transmission providers will voluntarily choose to
implement 15-minute transmission scheduling in order to better manage
variations in generation output. We understand that the existence of
compatible business practices within a region is beneficial, and we
encourage both jurisdictional and non-jurisdictional transmission
providers to continue to coordinate and collaborate in order to
maintain the continuity of the system and address issues as they arise.
This includes collaboration in the development of any alternative
compliance proposals developed by public utility transmission
providers.
---------------------------------------------------------------------------
\152\ E.g., Avista; California ISO; Duke; Idaho Power;
NorthWestern; NV Energy; PNW Parties; Puget; Southern California
Edison; Southern; Tres Amigas.
---------------------------------------------------------------------------
110. The Commission disagrees with comments by Southern and others
that different scheduling intervals between jurisdictional and non-
jurisdictional transmission providers may negatively affect reliability
within an interconnection.\153\ In the event a non-jurisdictional
transmission provider only accepts hourly schedules, any attempt to
submit an intra-hour schedule for delivery to the non-jurisdictional
transmission provider would be rejected, as several commenters
note.\154\ This may lead to an inability to implement 15-minute
scheduling fully and, in turn, could result in less effective
management of system variability. However, the Commission does not
believe that it would create any reliability challenges beyond those
that exist today under hourly scheduling protocols. The Commission
notes that voluntary efforts to implement intra-hour scheduling on 30-
minute intervals in the Western Interconnection referenced above have
not been uniformly applied, yet do not appear to have negatively
affected reliability.
---------------------------------------------------------------------------
\153\ E.g., EEI; Idaho Power; NorthWestern; Southern; Tacoma
Power.
\154\ E.g., PNW Parties; Puget; WUTC.
---------------------------------------------------------------------------
111. In response to concerns raised by Snohomish County PUD and
Grays Harbor PUD regarding ``slice'' contracts with Bonneville Power,
the Commission acknowledges that some existing power supply
arrangements may not be flexible enough to take advantage of the
benefits of intra-hour scheduling. Over time, the Commission
anticipates that the market will respond to the availability of intra-
hour scheduling through the development of new balancing products as
well as modifications of existing arrangements where appropriate.
However, in the case where the terms of an existing contract are
inconsistent with intra-hour scheduling and cannot be modified, the
Commission appreciates that the benefits of intra-hour scheduling may
not be available with respect to that particular transaction.
112. In response to comments by WestConnect and NorthWestern that a
15-minute scheduling interval is inconsistent with the standard 20-
minute generator ramp rate used in the West, we note that many of the
Joint Initiative transmission providers--including members from
WestConnect--have already implemented a 10-minute ramp rate to
accommodate 30-minute transmission schedules. To the extent changes in
ramping are necessary to support use of a 15-minute transmission
schedules, it does not appear that such changes present a significant
impediment for public utility transmission providers.
113. A number of commenters question the applicability of the
intra-hour scheduling requirements to public utility transmission
providers in RTO and ISO regions.\155\ The Commission clarifies that
the implementation of 15-minute transmission scheduling will only apply
to intertie transactions in organized wholesale energy markets. The
Commission finds that a consistent scheduling interval for transactions
among all public utility transmission providers, including RTOs, is
necessary in order to attain the benefits of intra-hour scheduling
noted above. Additional reforms to other markets requested by
commenters, such as adjustments to day-ahead markets, are beyond the
scope of this rulemaking.
---------------------------------------------------------------------------
\155\ E.g., AWEA; Iberdrola; ISO New England; Massachusetts DPU;
PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas;
Western Farmers.
---------------------------------------------------------------------------
2. Implementation of Intra-Hour Scheduling
114. Commenters raise a number of additional issues related to how
the intra-hour scheduling requirements adopted in this Final Rule
should be implemented. The Commission addresses these issues below,
including the following: (1) The appropriate notification period for
submitting transmission schedules; (2) the recovery of costs associated
with implementing intra-hour scheduling; (3) clarifications regarding
the definition of transmission schedule, curtailment priorities, and
calculations of ATC; (4) review of NERC reliability standards and NAESB
business practices; and (5) other issues related to high voltage direct
current (HVDC) transmission lines, dynamic scheduling, and the
geographic location of resources used to provide reserves.
a. Notification Time for Submission of Transmission Schedule
i. Commission Proposal
115. In the Proposed Rule, the Commission proposed to allow all
transmission customers the option of submitting intra-hour schedules up
to 15 minutes before each scheduling interval.\156\
---------------------------------------------------------------------------
\156\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 41.
---------------------------------------------------------------------------
ii. Comments
116. Several commenters ask the Commission to retain the existing
20-minute notification time for submission of transmission schedules,
arguing that schedules should be submitted no later than 20 minutes
prior to the start of the schedule as required by NERC Reliability
Standards INT-005, INT-006, INT-008, and NAESB WEQ-004 Appendix D.\157\
Commenters contend that allowing only 15 minutes between schedule
submission and start would not provide enough time for transmission
operators to adequately evaluate, approve, and implement transmission
schedules. ISO/RTO Council adds that changing to a 15-minute notice
period will require
[[Page 41504]]
transmission operators to change their current systems and increase
staff levels for processing transmission schedule requests. PJM
comments that the 20-minute notification deadline is an established
industry standard and that it should not be changed to 15 minutes.
---------------------------------------------------------------------------
\157\ E.g., Duke; EEI; Entergy; NRECA; PJM; Puget; Southern.
---------------------------------------------------------------------------
117. Although not opposed to the Commission's proposal, NaturEner
states that a shorter notification period would result in abbreviated
response times for everyone in the scheduling process, including
transmission customers. NaturEner asks the Commission to clarify that
transmission providers have the discretion to accept schedule changes
after the notification deadline. NaturEner contends that inclusion of
such a clarification both supports the reform's underlying rationales
and avoids any unnecessary future confusion regarding whether a
balancing authority or transmission provider possesses such discretion.
iii. Commission Determination
118. The Commission will retain the existing 20-minute prior
notification period for the submission of a transmission schedule and
not adopt its proposal. The Commission agrees with commenters that the
existing 20-minute prior notification period is needed to adequately
evaluate, approve and implement transmission schedules. Accordingly,
the Commission retains the existing notification period set forth in
sections 13.8 and 14.6 of the pro forma OATT, which permits scheduling
changes up to 20 minutes (or a reasonable time that is generally
accepted in the region and is consistent and adhered to by the
transmission provider) before the start of the next schedule change
provided that the delivering party and receiving party also agree to
the schedule modification. In response to NaturEner, the existing
language of the pro forma OATT provides adequate flexibility for
transmission providers to adopt alternative deadlines for accepting
scheduling changes.
b. Recovery of Intra-Hour Scheduling Costs
i. Commission Proposal
119. In the Proposed Rule, the Commission proposed to allow public
utility transmission providers to recover any costs incurred to
implement the proposed intra-hour scheduling reform pursuant to
Schedule 1 of a transmission provider's OATT.\158\
---------------------------------------------------------------------------
\158\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 41.
---------------------------------------------------------------------------
ii. Comments
120. Several commenters support the Commission's proposal, arguing
that the benefits of intra-hour scheduling apply to more than VERs and,
thus, costs relating to the implementation of intra-hour scheduling
should be allocated to all transmission customers under Schedule 1 of
the pro forma OATT.\159\ For example, NextEra contends that intra-hour
scheduling would provide long-term benefits for all customers through
savings on reserve procurement. Public Interest Organizations agree,
arguing that the initial costs of establishing 15-minute scheduling are
an upfront investment that will yield exponential returns over time in
the form of direct economic savings from increased grid efficiency and
reliability, as well as energy security, greenhouse gas and other
pollutant reductions, and job creation that accompanies increased
renewable VER penetration. Center for Rural Affairs supports recovery
of intra-hour scheduling costs to all beneficiaries through Schedule 1
in order to mitigate any challenge that this reform may present for
small transmission providers, especially in rural communities with
smaller areas of distribution. NaturEner points to the Joint Initiative
as an example of allocating the hardware and software costs associated
with implementation of intra-hour scheduling to all participants using
the intra-hour scheduling system, i.e., the balancing authorities,
transmission providers, and transmission customers. While Organization
of Midwest ISO States supports the proposal, it asks that a clear
showing of the costs incurred to implement intra-hour scheduling be
required prior to allowing for recovery of those costs.
---------------------------------------------------------------------------
\159\ E.g., Environmental Defense Fund; NextEra; Public Interest
Organizations.
---------------------------------------------------------------------------
121. Other commenters disagree with the Commission's proposal to
allow the costs associated with implementing intra-hour scheduling to
be recovered through Schedule 1 and, instead, contend that such costs
should be allocated to VERs and their customers.\160\ These commenters
argue that intra-hour scheduling will be predominantly used by and
benefit VERs and their customers.\161\ ELCON contends that traditional
generation resources do not require intra-hour scheduling. In the
Pacific Northwest, WUTC claims that intra-hour scheduling would be
utilized almost exclusively by wind and other VERs, and not by thermal
or hydropower resources. WUTC agrees that assignment of costs to those
who cause them is essential to fair and just rates and to economic
efficiency. Puget agrees that the only parties to benefit from 15-
minute scheduling are VERs that are potentially able to reduce Schedule
9 generator imbalance charges by adjusting their schedules within the
hour in response to changing wind conditions. Natural Gas argues that
strict adherence to cost causation principles is central to ensuring
that the proposals are limited to removing barriers and do not have the
unintended consequence of subsidization and, ultimately, departure from
the central precept of fuel neutrality.
---------------------------------------------------------------------------
\160\ E.g., Avista; ELCON; Grant PUD; Montana PSC; Natural Gas;
NorthWestern; NRECA; Puget; WUTC.
\161\ E.g., Avista; ELCON; Grant PUD; MidAmerican; NorthWestern;
NRECA; Puget; WUTC.
---------------------------------------------------------------------------
122. Montana PSC states that traditional generation choosing to
utilize intra-hour scheduling should be allocated a portion of
implementation costs; however, absent this election VERs should be
responsible for all costs related to development, operations, and
maintenance of intra-hour scheduling.\162\ NRECA similarly contends
that, if transmission customers other than VERs make use of the new
scheduling regime, it would be appropriate for those entities to share
in the cost through Schedule 1 charges. Grant PUD argues that there is
no guarantee that other resources may benefit from a shorter scheduling
period and that some resources may actually incur costs to maintain 15-
minute schedules, in which case they would pay twice for the shift to
shorter schedules.
---------------------------------------------------------------------------
\162\ Similarly, NorthWestern asserts that unless intra-hour
scheduling is made mandatory for all transmission customers, the
VERs opting to use intra-hour scheduling should pay for the
increased scheduling flexibility and the non VER customers should
not be required to subsidize any particular generator type.
---------------------------------------------------------------------------
123. Avista asserts that allowing recovery through Schedule 1 will
allocate costs not only to all transmission customers, but also to
bundled retail native load customers. Avista argues that native load
customers achieve no cost savings when a VER is located within a
balancing authority area and is used to serve load within the same
balancing area. Avista states that in this situation the native load
customers bear all of the costs associated with following the output of
the VER and do not need or benefit from intra-hour scheduling. Thus,
Avista requests that none of the costs of implementing intra-hour
scheduling be
[[Page 41505]]
borne by a transmission provider's bundled retail native load
customers.
124. Several of these commenters recommend that the Commission
consider other mechanisms for recovering the costs of implementing
intra-hour scheduling as opposed to a broad cost allocation scheme
through Schedule 1.\163\ For example, Avista asks the Commission to
allow a transmission provider to directly assign the costs of
implementing these reforms to the VER transmission customers that are
the cause of such reforms through an appropriate charge included in
either Schedule 1 or Schedule 10. NRECA argues that there is more than
one method that a public utility transmission provider could use to
recover costs and requests that the Commission provide public utility
transmission providers the flexibility to choose the method that works
best for each system and demonstrate a just and reasonable rate
pursuant to section 205 of the FPA. NRECA also urges the Commission to
include costs incurred to comply with any new Reliability Standards
that ensue from the Final Rule.
---------------------------------------------------------------------------
\163\ E.g., Avista; Grant PUD; NRECA; Puget.
---------------------------------------------------------------------------
iii. Commission Determination
125. The Commission adopts its proposal and allows public utility
transmission providers to recover any costs incurred to implement the
intra-hour scheduling reforms adopted in this Final Rule pursuant to
Schedule 1 of the transmission provider's OATT. The Commission is not
persuaded by commenters opposing the proposal that recovery of these
costs through Schedule 1 will result in an overly broad assignment of
costs. Such commenters argue that only a subset of transmission
customers is likely to use intra-hour scheduling and that only those
customers should bear the cost of implementing intra-hour scheduling
reforms. The Commission disagrees. As discussed above, intra-hour
scheduling provides all transmission customers with the tools needed to
mitigate exposure to Schedule 9 generator imbalance charges in light of
changing conditions.\164\ Implementation of intra-hour scheduling is
also necessary to the extent sellers wish to develop intra-hour energy
products to maximize the value of available resources or to allow load
serving entities to lower purchased power costs.\165\ The Commission
finds that these benefits will be spread broadly across customer
classes.
---------------------------------------------------------------------------
\164\ See supra Sec. IV.A.1 (Intra-Hour Scheduling
Requirement).
\165\ Id.
---------------------------------------------------------------------------
126. Moreover, commenters opposing the Commission's proposal fail
to reconcile their position with existing approaches used to recover
scheduling-related costs under Schedule 1 of the pro forma OATT.
Transmission providers do not currently parse scheduling costs into,
for example, categories for network customers and point-to-point
customers even though at times scheduling reforms have focused on one
set of customers and not the other.\166\ Rather, transmission customers
as a whole have allocated the costs of scheduling-related activities
through Schedule 1: Scheduling, System Control and Dispatch Service,
and relevant allocations to retail native load have been made by public
utility transmission providers. Commenters have failed to justify why
the Commission should depart from this precedent during implementation
of intra-hour scheduling practices.
---------------------------------------------------------------------------
\166\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 770.
---------------------------------------------------------------------------
127. In response to NRECA, the Commission's focus in this
proceeding is on the implementation of intra-hour scheduling and, as
relevant here, the recovery of scheduling-related implementation costs
pursuant to Schedule 1 of the pro forma OATT. The Commission did not
propose to address, and does not address here, recovery of other costs
associated with compliance with NERC Reliability Standards.
c. Clarify Proposed Rule Language
i. Comments
128. Commenters ask the Commission to clarify what is intended by
the terms schedule and scheduling interval. Southern and EEI state that
the term ``schedule'' is not well defined throughout the electric
industry and requests that the Commission clarify that ``schedule'' is
equivalent to ``Interchange Transaction'' in the NERC Reliability
Standards Glossary of Terms. TVA suggests that ``scheduling intervals''
coincide with the ``ramp start'' times as defined in the Timing
Requirements tables of the NERC Reliability Standards INT-005-3,
Interchange Authority Distributes Arranged Interchange; INT-006-3,
Response to Interchange Authority; and INT-008-3, Interchange Authority
Distributes Status. TVA contends that to view the term ``scheduling
interval'' otherwise would deviate from NERC Reliability Standards and
potentially have an adverse effect on assessment periods for
reliability.
129. Bonneville Power requests that the Commission clarify the
responsibilities of source and sink balancing authorities in regards to
holding contingency reserves associated with scheduling of VER
generation. Bonneville Power states that there is a debate regarding
whether and when a source or sink balancing authority should deploy
contingency reserves when a VER scheduling error exhausts the available
balancing reserve capacity. Bonneville Power asks the Commission to
clarify that a transmission provider can establish a base obligation to
provide balancing reserve capacity to balance VERs and that the
transmission provider can negotiate options for additional service
beyond the base obligation with individual transmission customers.
130. A few commenters request clarification of the appropriate
curtailment priority for intra-hour transmission schedules under the
proposed reform.\167\ Specifically, these commenters inquire as to
whether a firm transmission reservation that is scheduled for less than
the full hour would have priority over a non-firm hourly schedule.
Bonneville Power and NRECA contend that submission of a firm intra-hour
schedule should not necessarily result in the curtailment of lower
priority hourly schedules. MidAmerican requests that the Commission
clarify whether the submission of an intra-hour schedule by a
transmission customer with firm transmission rights, after a competing
intra-hour schedule from a transmission customer with only non-firm
transmission rights, has curtailment priority.
---------------------------------------------------------------------------
\167\ E.g., Bonneville Power; EEI; MidAmerican; NRECA.
---------------------------------------------------------------------------
131. Other commenters question how ATC calculations should be
performed after implementation of intra-hour scheduling.\168\ Public
Interest Organizations state that current policy in the West does not
allow ATC associated with transmission reservations that are not
scheduled day-ahead to be used by other customers. Public Interest
Organizations suggest that this policy may severely constrain or
prohibit the effectiveness of intra-hour scheduling. In addition,
Tacoma Power suggests that it may be appropriate to align ATC
calculations with intra-hour scheduling intervals. Invenergy Wind
asserts that the entire operational construct needs to shift from an
hourly to a 15-minute basis in order to increase the efficiency of
operating
[[Page 41506]]
the transmission system and acquiring sufficient reserves in order to
integrate VERs on a non-discriminatory basis. However, NorthWestern
argues that continued use of hourly transmission service reservations
would not be inconsistent with implementation of intra-hour
transmission scheduling, stating that administering intra-hour
transmission reservations would be difficult and costly.
---------------------------------------------------------------------------
\168\ E.g., Public Interest Organizations; Tacoma Power.
---------------------------------------------------------------------------
132. Grant PUD makes reference to the Commission's use of the term
``reasonable control'' in the Proposed Rule, where the Commission
states that it is unduly discriminatory to continue to require a
resource to match an hourly schedule, especially when the output of the
resource fluctuates beyond its reasonable control.\169\ Grant PUD
contends that what is reasonable depends on the current state of
technology and requests that the Commission clarify that the definition
of ``reasonable control'' is expected to improve over time.
---------------------------------------------------------------------------
\169\ Grant PUD (citing Proposed Rule, FERC Stats. & Regs. ]
32,664 at P 39).
---------------------------------------------------------------------------
ii. Commission Determination
133. In response to Southern and EEI, the Commission clarifies that
the term ``schedule'' as used in this Final Rule is equivalent to its
use in Schedule 9 of the OATT: ``* * * a delivery schedule from [a]
generator to (1) another Control Area or (2) a load within the
Transmission Provider's Control Area.'' \170\ The procedures for
submitting and revising a transmission schedule are delineated in
sections 13.8 and 14.6 of the pro forma OATT, as changed by this Final
Rule. Any transmission service schedule currently submitted pursuant to
OATT sections 13.8 and 14.6 can therefore be modified or created in 15-
minute intervals under this Final Rule.
---------------------------------------------------------------------------
\170\ OATT Schedule 9.
---------------------------------------------------------------------------
134. In response to TVA, the Commission clarifies that the 15-
minute scheduling interval will be treated the same as the current one-
hour scheduling interval with respect to ramp start and stop times as
defined in the Timing Requirements tables of NERC Reliability Standards
INT-005-3, INT-006-3, and INT-008-3. As an example, in the Eastern
Interconnection ramp start times will begin five minutes before the
start of the 15-minute scheduling interval and end five minutes after
the start of the 15-minute scheduling interval.
135. Regarding responsibilities for holding contingency reserves,
the Commission did not propose any changes to existing rules regarding
the use of contingency reserves in this proceeding. As Bonneville Power
notes, there is ongoing debate in the industry regarding when and how
contingency reserves may be used under NERC Reliability Standards. The
Commission concludes it is appropriate, in the first instance, for
stakeholders to address these questions through the NERC
processes.\171\
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\171\ The Commission addresses requests by Bonneville Power and
others to limit the amount of capacity it must make available to
transmission customers for generator regulation service under
Schedule 10 in Sec. IV.C.1 (Schedule 10--Generator Regulation and
Frequency Response Service) below.
---------------------------------------------------------------------------
136. The Commission also did not propose any changes to curtailment
policies or ATC calculation. The Commission recognizes that
transmission providers have flexibility under the pro forma OATT to
award transmission service based on transmission capability that
becomes available when firm transmission service is not scheduled by
10:00 a.m. the day prior to operation.\172\ The Commission appreciates
that, when a transmission provider makes service available under these
circumstances, application of curtailment priorities and ATC
calculation rules become more complicated. However, that is already the
case under hourly transmission schedules. Therefore, the Commission did
not propose any change to those practices to accommodate the
possibility of intra-hour transmission schedules. All transmission
schedules for firm service will continue to have curtailment priority
over all transmission schedules for non-firm service \173\ and
transmission providers will continue to be required to follow existing
rules governing the calculation of ATC.\174\
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\172\ The pro forma OATT states that ``[s]chedules for the
Transmission Customers' Firm Point-To-Point Transmission Service
must be submitted no later than 10:00 a.m. * * * of the day prior to
commencement of such service.'' OATT Schedule 13.8.
\173\ The pro forma OATT makes clear that ``(p)arties requesting
Non-Firm Point-To-Point Transmission Service for the transmission of
firm power do so with the full realization that such service is
subject to availability and to Curtailment or Interruption under the
terms of the Tariff.'' OATT Schedule 14.5.
\174\ In compliance with Order No. 890, public utility
transmission providers have documented rules governing their
calculation of ATC in Schedule C of their OATTs. See Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 193.
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137. In response to the request from Grant PUD for clarification of
the term ``reasonable control,'' the Commission explains that use of
the term ``reasonable control'' is not intended to be a metric or a
determining factor, but illustrative of the difficulty VERs experience
when attempting to follow hourly schedules accurately. The Commission
does not find it necessary to offer any further clarification.
d. NERC and NAESB Standards
i. Commission Proposal
138. In the Proposed Rule, the Commission noted that many
commenters, in response to the NOI, claimed that shorter scheduling
intervals may enhance reliability. The Commission therefore stated that
it did not believe that an independent review of NERC Reliability
Standards is necessary in order to propose implementation of intra-hour
scheduling. However, the Commission sought comment on the issue to
ensure that there is no inconsistency between relevant NERC standards
and the proposed intra-hour scheduling tariff reform.\175\
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\175\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 37.
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ii. Comments
139. NERC states that certain entities currently offer 15-minute
scheduling and that it is unaware of any conflicts with Reliability
Standards. However, NERC asserts that wide spread use of intra-hour
scheduling will likely require review and refinement of several
existing Reliability Standards. Based on its preliminary review of
Reliability Standards in coordination with industry stakeholders, NERC
states that it does not believe there are any insurmountable hurdles
that prevent industry from implementing 15-minute transmission
scheduling. NERC explains that sufficient time must be allowed for
Reliability Standards to be modified through the NERC Reliability
Standards Committee prioritization process, but that transitioning to
broad intra-hour scheduling flexibility is achievable in a reasonable
timeframe.
140. Some commenters do not anticipate that a review of NERC
Reliability Standards is necessary to ensure reliability upon the
implementation of intra-hour scheduling.\176\ NaturEner argues that an
independent review of NERC standards may not be necessary, but if such
a review occurs it should not delay implementation of intra-hour
scheduling. Pacific Gas & Electric agrees that implementation of intra-
hour scheduling can be achieved without a review of NERC standards, but
recommends that NERC and other industry experts review and update
current planning and operating criteria to ensure that balancing
authorities have the necessary tools to flexibly balance
[[Page 41507]]
loads and resources with the advent of increased VER penetration.
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\176\ E.g., NaturEner; Southern California Edison.
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141. Other commenters contend that review and modification of
standards may be necessary, but not a prerequisite to
implementation.\177\ Southern and Xcel state that only modest, if any,
changes would be needed to NERC Reliability Standards. Southern
indicates that several standards may need to be reviewed and revised as
they currently contemplate hourly intervals. Xcel contends that
standards related to the maximum lead times required for entry and
approval of a schedule may require changes. Xcel explains that the lead
times for entry and approval of a tag may exceed the length of a
scheduling interval, thus diminishing the usefulness of intra-hour
scheduling. AEP and Duke Energy suggest that sensitivity studies should
be performed by an industry forum or working group to determine the
reliability impacts of the proposed scheduling changes on real-time
system operations.
---------------------------------------------------------------------------
\177\ E.g., NERC; Pacific Gas & Electric.
---------------------------------------------------------------------------
142. Several commenters argue that review and revision of NERC
Reliability Standards, as well as NAESB business practice standards,
may be necessary for the implementation of intra-hour scheduling at 15-
minute intervals.\178\ These commenters point out that many Reliability
Standards and business practices are largely predicated on hourly
scheduling intervals and govern transactions both internal to a
particular balancing authority as well as across neighboring balancing
authorities. Although most commenters did not identify specific changes
to standards that would be necessary, some commenters suggest that NERC
Reliability Standards related to some or all of the following areas be
reviewed: Interchange Scheduling and Maintenance Coordination (INT),
Resource and Demand Balancing (BAL), Emergency Preparedness and
Operations (EOP), and Transmission Operations (TOP) standards.\179\
Additionally, commenters indicate that reliability scheduling tools,
such as the Interchange Distribution Calculator used in the Eastern
Interconnection and the WebSAS system used in the Western
Interconnection for scheduling, curtailment and ``check out'' processes
may also require modification.\180\
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\178\ E.g., Bonneville Power; Duke; EEI; MidAmerican; NRECA;
PNW Parties; Southern.
\179\ E.g., Duke; EEI; NERC; NRECA; PNW Parties; Southern.
\180\ E.g., NERC; NRECA; Southern.
---------------------------------------------------------------------------
143. NRECA cautions that any modifications to NERC standards should
allow for the implementation of intra-hour scheduling but not mandate
this practice. NRECA suggests that NERC be allowed to complete any
updates to its standards associated with implementation of intra-hour
scheduling prior to NAESB undertaking a review to ensure uniformity of
approaches. NV Energy notes that, in order to schedule at 30 minute
intervals or less, the protocols to effectuate such transactions must
be agreed upon by all entities in WECC. Therefore, NV Energy requests
that the Commission defer issuance of the Final Rule until the industry
has had the opportunity to address NERC, WECC and NAESB standards
issues.
144. PNW Parties state that the Joint Initiative participants found
it necessary to review NERC and NAESB standards as part of their
development of a 30-minute scheduling program, but did not identify in
comments whether any changes to standards or business practices were
needed. PNW Parties suggests, however, that applicable standards and
business practices be reviewed and revised as necessary prior-to
implementing more granular scheduling.
145. Some commenters within the VER industry request clarification
and/or modification of NERC scheduling protocols to allow for a
resource to be indentified as a ``sink.'' \181\ These commenters claim
that this is necessary because under the Commission's proposed reforms
VERs will be transacting on an intra-hour basis in order to supplement
their variable supply. Iberdrola explains that, in order to enter into
bilateral transactions for balancing energy where a VER's 15-minute
schedule is less than its hour-ahead schedule, the additional balancing
energy purchased from a generator with excess energy would need to be
tagged as the ``source'' and the VER would need to be tagged as the
``sink.'' Iberdrola claims that this is necessary because VERs will be
transacting bilaterally in the sub-hourly timeframe in an effort to
maintain the schedule that was entered prior to the operating hour.
AWEA agrees, arguing that some of the benefits of intra-hour scheduling
will not be realized without this additional clarification. In response
to the potential concerns of transmission providers regarding
generators being tagged as sinks, AWEA and Iberdrola argue that
reliability concerns would only be present when the ultimate delivery
point is unknown.\182\ AWEA explains that the case presented by a VER
transacting as a sink for intra-hour scheduling purposes is entirely
different, as the ultimate delivery point is already known. In this
case, AWEA points out that there is a schedule to deliver energy to a
real load and explains that this schedule is delivering energy to the
load which the VER is unable to serve. Therefore, AWEA and Iberdrola
conclude that such scheduling practices do not present reliability
concerns.
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\181\ E.g., AWEA; Iberdrola.
\182\ E.g., AWEA; Iberdrola.
---------------------------------------------------------------------------
iii. Commission Determination
146. The Commission concludes that an independent review of NERC
standards and NAESB business practices is not necessary prior to the
implementation of intra-hour scheduling. As noted by NERC, several
entities currently offer intra-hour scheduling without any apparent
conflict with Reliability Standards. NERC comments that it does not
believe there are any existing standards that prohibit industry from
implementing intra-hour scheduling, and no commenters have pointed to
specific NAESB business practices that prevent industry from
implementing intra-hour scheduling. The Commission therefore concludes
that it is not necessary to delay adoption of the intra-hour scheduling
requirements of this Final Rule pending further review of NERC
Reliability Standards and NAESB business practices. To the extent
industry believes it is beneficial to refine one or more existing NERC
Reliability Standards or NAESB business practices to reflect intra-hour
scheduling, stakeholders can use existing processes to pursue such
refinements.
147. With regard to the requests from AWEA and Iberdrola to allow a
VER resource to be designated as a ``sink'' for purposes of
transmission scheduling, rules for scheduling transmission segments are
set forth in NAESB's Coordinate Interchange Standards,\183\ which have
been incorporated into the Commission's regulations by reference.\184\
The Proposed Rule did not propose any changes to those rules and the
Commission declines to interpret the application to any particular
transactions in this generic rulemaking proceeding.
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\183\ NAESB WEQ-004, App. C, Sec. 2 (Commercial Timing Table).
\184\ See 18 CFR 38.2 (2011).
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3. Other Issues
a. Comments
148. Several commenters question the application of intra-hour
scheduling reforms to HVDC transmission lines. Clean Line states that
HVDC
[[Page 41508]]
transmission lines can precisely control power and, thus, are typically
expected to submit schedules to public utility transmission providers.
Clean Line requests that HVDC transmission lines receive equal
treatment and be allowed to submit intra-hour schedules on the same
basis as generators. In contrast, ALLETE and Midwest ISO Transmission
Owners both request that the Commission grant an exemption from 15-
minute schedules for HVDC transmission lines. These commenters argue
that 15-minute scheduling of HVDC transmission lines could lead to an
increase in the duty on the load tap changers of HVDC converter
transformers, potentially resulting in an increase in maintenance costs
and an increased potential of transformer failure.
149. Bonneville Power raises questions regarding the impact of
intra-hour scheduling on dynamic scheduling practices. Bonneville Power
states that 15-minute scheduling will lead to increased ramping and
inhibit the availability of dynamic transfer capability in areas where
dynamic transfer capability is limited, such as the Bonneville Power
system and other parts of the West. Bonneville Power contends that 30-
minute scheduling relieves this problem and requests that the
Commission gain a better understanding of the impacts that 15-minute
scheduling will have on dynamic transfers. In contrast, First Wind
requests that the Commission encourage dynamic transfers in addition to
implementing intra-hour scheduling, suggesting that dynamic transfers
can reduce regulation service requirements for transmission owners and
transfer regulation requirements to purchasers of VER energy. First
Wind also argues that intra-hour scheduling and dynamic transfers will
allow for better tracking of real-time generation and reduce the need
for ancillary services while increasing opportunities for flexible
generation and demand response.
150. M-S-R Public Power Agency states that shortening the
scheduling interval does not reduce the intermittency of the VERs
themselves. M-S-R Public Power Agency offers that as a matter of
physics a VER requires a back-up resource to ``balance'' its
intermittency, irrespective of scheduling, adding that while a shorter
scheduling interval may mitigate the number of megawatts needed to
assure reliability, it will not mitigate the location or cost of back-
up reserves. M-S-R Public Power Agency goes on to state that VER
penetration levels of 20-25 percent start to exhaust the capability of
even the most robust systems and that the proposed mitigation may be
insufficient. M-S-R Public Power Agency explains that the raw energy of
VERs must be converted to conditioned energy (traditional resources) at
the source, and not shifted to other locations through mitigation, or
there will be a degradation of services to all VERs within that system.
M-S-R Public Power Agency states that intermittent resources require
that the transmission owner have nearly infinite capability to provide
backup resources; however, even the most robust balancing authority has
limitations of how fast, how often, and when it can provide back up
resources. M-S-R Public Power Agency offers that, with both the cost of
transmission and reliability (back-up generation) challenges, VERs may
be uneconomic. M-S-R Public Power Agency encourages the Commission to
solicit input on this issue.
Commission Determination
151. All transmission customers that are currently eligible to
submit hourly energy schedules will be eligible to participate in
intra-hour scheduling, including HVDC lines that currently submit
hourly energy schedules. To the extent a transmission provider believes
an exemption is appropriate, it has the right to request a waiver of
all or part of the OATT requirements as described in 18 CFR 35.28(d):
``A public utility subject to the requirements of this section and
Order No. 889, FERC Stats. & Regs. ]31,037 (Final Rule on Open Access
Same-Time Information System and Standards of Conduct) may file a
request for waiver of all or part of the requirements of this section,
or Part 37 (Open Access Same-Time Information System and Standards of
Conduct for Public Utilities), for good cause shown.'' Waiver requests
will be evaluated in separate proceedings if and when they are
submitted based on the facts and circumstances of each request.
152. With regard to the use of dynamic schedules, the Commission
did not propose and is not adopting any change in policy with regard to
dynamic scheduling. The Commission is not persuaded by arguments from
Bonneville Power that 15-minute scheduling intervals will negatively
affect dynamic transfer capability. However, the Commission
acknowledges that a transmission provider's implementation of charges
for generator regulation service, as discussed in the following
section, may have the result of encouraging the use of dynamic
scheduling to avoid such charges.
153. In response to M-S-R Public Power Agency, the Commission
appreciates that the location of a particular resource can be relevant
in determining whether it can be used to satisfy reserve obligations.
That is, a public utility transmission provider providing ancillary
services under the pro forma OATT, or a transmission customer self-
supplying such ancillary services needs transmission capacity to ensure
deliverability of a particular resource. Whether that is the case will
be fact specific and we expect the transmission provider to take the
appropriate steps to ensure such transmission capacity is available.
B. Data Reporting To Support Power Production Forecasting
154. The second of the two reforms adopted in this Final Rule
relates to the submission of meteorological and forced outage
data,\185\ by new interconnection customers whose generating facilities
are VERs, to the public utility transmission provider with which the
customer is interconnected if the public utility transmission provider
is doing power production forecasting. As discussed below, the
Commission amends the pro forma LGIA to effectuate this data reporting
requirement. The Commission concludes that, without these reporting
requirements in place, the terms of the pro forma LGIA may impair the
ability of public utility transmission providers to develop and deploy
power production forecasting, which in turn can lead to rates for
jurisdictional services that are unjust and unreasonable or unduly
discriminatory.
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\185\ The Proposed Rule used the term ``operational data'' and
specified forced outages as a particular type of operational data.
To reflect the limited nature of data to be reported under this
Final Rule more accurately, the Commission instead refers more
specifically to ``forced outage data'' in our determinations here
and accompanying revisions to the pro forma LGIA. We also note that
Section 9.7.1 of the LGIA requires Transmission Providers and
Interconnection Customers to coordinate and report planned outages.
Within the context of this Final Rule, the Commission references the
term ``forced outage'' as defined by NERC. See NERC Glossary of
terms available at http://www.nerc.com/files/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------
1. Data Requirements
a. Commission Proposal
155. To facilitate the development and deployment of power
production forecasting by public utility transmission providers, the
Proposed Rule set forth revisions to the pro forma LGIA that would
require interconnection customers whose generating facilities are VERs
to provide certain meteorological and operational data to the public
utility transmission provider with whom they are
[[Page 41509]]
interconnected, if doing forecasting. The Commission proposed that such
data would be transmitted from the interconnection customer to the
public utility transmission provider at or near real-time. The
Commission stated that this proposal built on existing Commission data-
sharing requirements by outlining specific meteorological and
operational data necessary to develop power production forecasts.\186\
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\186\ See Proposed Rule, FERC Stats. & Regs. ] 32,664 at PP 60-
61.
---------------------------------------------------------------------------
156. With regard to the reporting of meteorological data, the
Commission proposed revisions to the pro forma LGIA that would result
in different types of meteorological information being provided by
interconnection customers based on the type of VER they own and/or
operate. The Commission proposed to require interconnection customers
whose generating facilities are wind-based VERs to provide public
utility transmission providers with site-specific meteorological data
including, but not limited to, temperature, wind speed, wind direction,
and atmospheric pressure. The Commission proposed to require
interconnection customers whose generating facilities are solar-based
VERs to provide public utility transmission providers with site-
specific meteorological data including, but not limited to,
temperature, atmospheric pressure, and cloud cover. The Commission
recognized that different power production forecasts may require
meteorological instruments to be located at hub height, up-wind of
resources, or at ground level. However, the Commission refrained from
proposing specific requirements in this respect and, instead, proposed
to allow the public utility transmission provider and interconnection
customers to negotiate these details taking into account the size and
configuration of the VER facility, its characteristics, location, and
importance in maintaining generation resource adequacy and transmission
system reliability in its area. The Commission stated that resource-
specific data requirements contained in individual LGIAs must be
negotiated on a not unduly discriminatory basis.\187\
---------------------------------------------------------------------------
\187\ See id. P 61.
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157. With respect to the reporting of operational data, the
Commission proposed to revise the pro forma LGIA to require
interconnection customers whose generating facilities are VERs to
report to the public utility transmission provider any forced outages
that reduce the generating capability of the resource by 1 MW or more
for 15 minutes or more. The Commission noted that provision of VER
outage data at this level of granularity would allow a public utility
transmission provider to ascertain the extent to which current VER
power production is a result of unit availability as opposed to
changing weather conditions.\188\ The Commission preliminarily found
that having such information would eliminate a significant source of
forecasting errors by ensuring that the public utility transmission
provider has accurate information regarding the capacity actually
available to produce electricity during the time-frame of the
operational forecasts.\189\
---------------------------------------------------------------------------
\188\ See id. P 62 (citing Cal. Indep. Sys. Operator Corp., 131
FERC ] 61,087, at P 64 (2010)).
\189\ Id. P 62.
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158. The Commission sought comment on the extent to which the lists
of basic meteorological and operational data articulated above may be
inadequate or incomplete in achieving the stated power production
forecasting goals.\190\
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\190\ Id. P 63.
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b. Comments
159. Commenters addressing the reporting of meteorological data
generally support requiring the provision of data as necessary to
enable public utility transmission providers to employ power production
forecasts.\191\ While disagreeing that public utility transmission
providers should be responsible for power production forecasting,
Montana PSC argues that, should the Commission impose forecasting
requirements, public utility transmission providers should have access
to all meteorological data that are site-specific to the VER, provided
that the parties have a confidentiality agreement in place to protect
proprietary information. BP Companies and First Wind request that the
Commission clarify that the proposal is only relevant to instances in
which the public utility transmission provider is developing and/or
implementing VER power production forecasting.
---------------------------------------------------------------------------
\191\ E.g., AWEA; Bonneville Power; California ISO; CEERT; Clean
Line; California PUC; Exelon; First Wind; Iberdrola; Independent
Energy Producers; Independent Power Producers Coalition-West; ISO/
RTO Council; ISO New England; Large Public Power; Midwest ISO;
Midwest ISO Transmission Owners; NaturEner; NextEra; NRECA; Pacific
Gas & Electric; PJM; Powerex.
---------------------------------------------------------------------------
160. Several commenters support the Commission's identification of
certain categories of meteorological data to be provided by wind and
solar resources.\192\ For example, with regard to wind resources,
Iberdrola agrees that wind speed, wind direction, temperature and
pressure are all key atmospheric variables related to wind farm output
and are the most important fields to measure. With regard to solar
resources, NextEra, SEIA, and Xcel generally support the minimum
categories of data identified in the Proposed Rule, but they suggest
that the Commission revise the reference to cloud cover because it is
ambiguous. Specifically, NextEra and SEIA recommend that the Commission
require solar resources to report diffuse, direct, and global
horizontal irradiance. NextEra adds that humidity should also be
provided for a solar VER using concentrating thermal solar technology,
while SEIA suggests that plane of array irradiance or direct normal
radiation may also be necessary. These commenters note that irradiance
is often a better measure because it actually drives energy production.
---------------------------------------------------------------------------
\192\ E.g., AWEA; Iberdrola; ISO New England; RENEW.
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161. Commenters generally support the Commission's proposal to
allow the public utility transmission provider and interconnection
customer to negotiate additional meteorological and operational data
reporting requirements.\193\ Commenters identified a variety of
additional meteorological and facility-specific data that may be useful
in developing and deploying power production forecasts. These
commenters generally note that regional differences may dictate
additional data needs,\194\ with several asking the Commission to
acknowledge that additional data beyond that specifically identified in
the Proposed Rule may be needed by a public utility transmission
provider.\195\
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\193\ E.g., Bonneville Power; ISO New England; ISO/RTO Council;
Large Public Power Council; Midwest ISO; NRECA; PNW Parties; RENEW;
Xcel.
\194\ E.g., Bonneville Power; First Energy; ISO New England;
ISO/RTO Council; NextEra; MidAmerican; Midwest ISO; Midwest ISO
Transmission Owners; NorthWestern; NRECA; Pacific Gas & Electric;
Xcel.
\195\ E.g., Bonneville Power; ISO New England; Midwest ISO;
NextEra; NRECA.
---------------------------------------------------------------------------
162. Several commenters raise concerns regarding the Commission's
discussion of the location of meteorological towers and other equipment
necessary to record and report data to public utility transmission
providers.\196\ NextEra asks that the Commission refrain from allowing
public utility transmission providers to require VERs to install
multiple meteorological towers, arguing that data beyond what is
available through one meteorological tower has little value for
advanced power production forecasting methods. Invenergy similarly
argues that a single meteorological tower per
[[Page 41510]]
facility is usually sufficient for predicting plant output.
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\196\ E.g., AWEA; Invenergy; NextEra.
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163. With regard to the frequency of reporting meteorological data,
several commenters suggest that the frequency of data reporting should
match the use of the data, which may not be at or near real-time.\197\
For example, AWEA, Iberdrola, and NextEra state that second-by-second
or minute-by-minute meteorological recordings yield minimal benefits
for forecasting accuracy and could be costly and burdensome. AWEA and
Clean Line suggest that a reasonable requirement for the frequency at
which real-time meteorological and operational data is reported from a
wind plant is 10 minutes or more. NorthWestern, however, states that it
would be helpful to require each VER to update the forecasting data
that it has provided to the public utility transmission provider when
it provides a new energy schedule.
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\197\ E.g., AWEA; Clean Line; Iberdrola; NextEra; NaturEner;
NorthWestern; Public Interest Organizations.
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164. AWEA and Iberdrola also contend that distinctions should be
made between the types of data that should be provided in real-time and
the types of data that should be provided historically. These
commenters state that archived time series data are crucial to
statistical forecasting techniques and that this application is not
done in real-time. AWEA and Iberdrola state that data needed for
forecast training can be compiled into larger datasets and transmitted
at less frequent intervals at a much lower cost. RenewElec and
Bonneville Power generally agree that there is significant value in
historical data recorded by VERs.
165. With regard to the operational data reporting requirements,
some commenters urge the Commission to adopt the proposed requirement
that VERs report to the public utility transmission provider any forced
outages that reduce the generating capacity of a resource by 1 MW or
more for 15 minutes or more.\198\ For example, Bonneville Power states
that having access to forced outage information will enable public
utility transmission providers to determine whether forecast inaccuracy
results from unit availability, changing weather conditions, or a
combination of the two. Bonneville Power further states that without
such information it will be difficult to verify forecasts and improve
forecast accuracy. California ISO requests that the Commission not
overturn its recent decision approving California ISO's 1 MW threshold
for reporting a forced outage of an eligible intermittent resource.
California ISO argues that outage reporting requirements that are less
stringent than those proposed would increase the likelihood that the
forecasting algorithm would accumulate inaccurate data.
---------------------------------------------------------------------------
\198\ E.g., Bonneville Power; California ISO; NRECA.
---------------------------------------------------------------------------
166. Other commenters acknowledge that forced outage data are
useful in developing power production forecasts, but disagree on the
exact reporting requirements.\199\ Some commenters contend that a 1 MW
reporting threshold would pose an unnecessary burden on a wind plant
owner/operator, yield minimal benefits for forecast accuracy, and pose
compliance difficulties.\200\ Instead of the proposed requirement,
NaturEner recommends requiring that only planned outages of greater
than 15 percent of the generator's capacity should be reported as soon
as they are known by the generator. AWEA suggests that reporting apply
only to forced outages that exceed 10 percent of the nameplate capacity
of a plant, a requirement that AWEA states is similar to the one
imposed on conventional generators. NextEra similarly asks that the
outage reporting requirements be identical to those that apply to
conventional resources. MidAmerican recommends that VER transmission
customers be required to report forced outages lasting more than 24
hours and involving the lesser of either 20 MW or 50 percent of
nameplate capacity. Xcel recommends that the Commission ask NERC to
analyze and determine the appropriate threshold level for reporting VER
outages to public utility transmission providers and balancing
authorities.
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\199\ E.g., AWEA; Exelon; NaturEner; SEIA; Xcel; MidAmerican;
NextEra.
\200\ E.g., AWEA; Iberdrola; NaturEner; MidAmerican; PJM.
---------------------------------------------------------------------------
167. SEIA contends that the forced outage reporting requirement may
be appropriate for large solar photovoltaic generators, but not for
concentrating solar plants that experience frequent changes in power
output. SEIA states that, with respect to concentrating solar power-
generating facilities, the Commission should consider a threshold for
reporting such fluctuations based either on the total capacity of the
facility or particular types of maintenance or repair activities that
would result in an outage at a percentage of the facility.
168. Exelon asks the Commission to clarify what constitutes a
forced outage for purposes of the requirement to report operational
data, suggesting it should only include unanticipated outage events.
NRECA notes that the Proposed Rule did not identify the frequency for
reporting operational data to the public utility transmission provider.
NRECA contends that the public utility transmission provider should be
notified as soon as the VER is aware of an outage.
169. Several commenters recommend that the Commission provide
regional flexibility with respect to the operational data reporting
requirements.\201\ For example, Iberdrola states that VER forced outage
reporting requirements should be regional and: (1) Based on the
penetration of VERs in the region; (2) based on the ability of the
transmission provider to incorporate the data into power production
forecasting from VERs that is in turn used for reliably operating the
system; and (3) limited to an interval that enables the use of
predictive outage reporting capability.
---------------------------------------------------------------------------
\201\ E.g., Iberdrola; ISO New England; Midwest ISO Transmission
Owners; PJM; Southern California Edison.
---------------------------------------------------------------------------
170. Some commenters argue that the Commission should acknowledge
the importance of standardized regional reporting mechanisms when
considering these proposed reforms.\202\ For example, Midwest ISO notes
that IEC Standard 61400-25 already exists to facilitate the exchange of
information between individual wind turbines, their constituent
components, wind power plants, area control, and other external
systems. Midwest ISO suggests that use of a common format for
communicating data between the VER and public utility transmission
provider would promote the development of power production forecasting.
However, Invenergy asks that the Commission make clear that public
utility transmission providers are required to accept reasonable
alternative means of data communication and not implement uniform
standards that impose unnecessary costs on wind projects.
---------------------------------------------------------------------------
\202\ E.g., Alstom; EEI; Midwest ISO.
---------------------------------------------------------------------------
c. Commission Determination
171. The Commission adopts, as modified below, the proposed
requirement that interconnection customers whose generating facilities
are VERs provide meteorological and forced outage data to the public
utility transmission provider with which the customer is
interconnected, where necessary for that public utility transmission
provider to develop and deploy power production forecasting. As
discussed below, power production forecasting can be used by public
utility transmission providers to operate their
[[Page 41511]]
systems and manage reserves more efficiently. To the extent a public
utility transmission provider seeks to rely on power production
forecasting, the Commission concludes it is appropriate to require new
interconnection customers whose generating facilities are VERs to
provide related data to the public utility transmission provider under
the circumstances below. The Commission therefore directs public
utility transmission providers to modify their pro forma LGIAs to
effectuate the data reporting requirement.
172. As the Commission noted in the Proposed Rule, industry studies
demonstrate the potential for significant benefits from the
incorporation of power production forecasts into scheduling and unit
commitment processes. In WECC alone, NREL estimated the use of VER
power production forecasts has the potential to reduce operating costs
by up to 14 percent or $5 billion per year.\203\ NERC has similarly
concluded that forecasting the output of variable generation is
critical to bulk power system reliability in order to ensure that
adequate resources are available for ancillary services and ramping
requirements.\204\ NERC has therefore recommended that forecasting
techniques be incorporated into day-to-day operational planning and
real-time operations routines/practices including unit commitment and
dispatch.\205\ The Commission notes that the benefits of power
production forecasting can accrue across a variety of time frames,
including the operating day, day-ahead, and seasonally.
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\203\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 45
(citing National Renewable Energy Laboratory, Western Wind and Solar
Integration Study ES-18 (2010), available at http://www.nrel.gov/wind/systemsintegration/wwsis.html).
\204\ NERC, Accommodating High Levels of Variable Generation 54
(2009), available at http://www.nerc.com/files/IVGTF_Report_041609.pdf.
\205\ Id. at 59.
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173. However, power production forecasts are only as good as the
data on which they rely. The ability of public utility transmission
providers to use power production forecasting in the commitment and de-
commitment of resources may be limited without adequate meteorological
and forced outage data from VERs. The current lack of meteorological
and forced outage data reporting requirements in the pro forma LGIA
therefore may limit efforts by public utility transmission providers to
more efficiently manage operating costs associated with the integration
of VERs interconnecting to their systems. Under the existing
requirements of the pro forma LGIA, public utility transmission
providers are permitted to request this information, but there is no
obligation for interconnection customers whose generating facilities
are VERs to provide it. The Commission remedies this deficiency by
adopting reporting requirements for new interconnection customers whose
facilities are VERs, commensurate with the power production forecasting
employed by the public utility transmission provider, to allow for more
accurate commitment and de-commitment of resources providing reserves,
ensuring that reserve-related charges imposed on customers remain just
and reasonable and not unduly discriminatory or preferential. The
Commission implements this requirement by requiring public utility
transmission providers to modify their pro forma LGIAs to include the
reporting requirements discussed below.
174. The reporting requirements adopted in this Final Rule are
specifically designed to support the development and deployment of
power production forecasting by public utility transmission providers.
As a result, nothing in this Final Rule should be construed as creating
an obligation for interconnection customers whose generating facilities
are VERs to provide meteorological and forced outage data in cases
where the public utility transmission provider is not engaging in power
production forecasting. The Commission recognizes that VER potential
and penetration varies across public utility transmission provider
systems and that, at this time, not all public utility transmission
providers have sufficient levels of VERs to warrant engaging in power
production forecasting. The Commission is nonetheless amending the pro
forma LGIA to ensure that those public utility transmission providers
seeking to develop and deploy power production forecasting in response
to increasing VER penetration have adequate information to do so. To
make the conditional nature of the reporting requirements clear, the
Commission revises the proposed Article 8.4 of the pro forma LGIA to
state that all requirements for meteorological and forced outage data
must be consistent with the power production forecasting employed by
the Transmission Provider, if any, to manage reserve commitments. The
Commission believes that this strikes a reasonable balance between the
requirement to provide the data and the public utility transmission
provider's use of the data to manage reserve commitments more
efficiently.
175. Turning to the particular reporting requirements imposed on
interconnection customers whose generating facilities are VERs, the
Commission affirms the approach set forth in the Proposed Rule allowing
public utility transmission providers flexibility in identifying the
specific meteorological and forced outage data to be reported. As
proposed, Article 8.4 of the pro forma LGIA would specify certain
categories of data to be provided by interconnection customers with
VERs having wind or solar as the energy source, with the exact
specifications of data to be provided taking into account the size and
configuration of the VER, its characteristics, location, and its
importance in maintaining generation resource adequacy and transmission
system reliability in its area. Some commenters generally support this
approach, stating that the type of power production forecasting
deployed by public utility transmission providers and the tools used to
perform forecasts could vary widely, and therefore any reporting
requirements associated with power production forecasting should be
flexible.\206\ This approach will provide public utility transmission
providers the flexibility to negotiate, in the first instance, with
interconnection customers whose generating facilities are VERs to
identify the particular data to be reported by the customer.
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\206\ E.g., Iberdrola; NextEra.
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176. The Commission finds that this flexible approach to
establishing data reporting requirements will ensure that all reporting
of meteorological and forced outage data corresponds with the power
production forecasting being employed by the public utility
transmission providers. To be clear, however, public utility
transmission providers cannot unduly discriminate among interconnection
customers with regard to data reporting requirements. By linking the
requirement to provide meteorological and forced outage data to the use
of these data by the public utility transmission provider in power
production forecasting to manage reserve commitments, the Commission
seeks to minimize opportunities for undue discrimination as well as
needless burden on interconnection customers. At the same time, to the
extent meteorological and forced outage data are needed for the public
utility transmission provider to engage in power production
forecasting, they must be provided by the interconnection customer,
even if that means investment in additional equipment by the
customer.\207\ To the extent there are
[[Page 41512]]
concerns of discriminatory or unnecessary application of data reporting
requirements, interconnection customers can request that the public
utility transmission provider file with the Commission an unexecuted
LGIA in order to resolve the disagreement.\208\
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\207\ The Commission acknowledges the concern of some commenters
that the installation of multiple meteorological towers would
increase costs for an interconnection customer. Whether data from a
single meteorological tower is sufficient to support the power
production forecasting deployed by the public utility transmission
provider should be addressed as part of the negotiation of the LGIA.
\208\ See 16 U.S.C. 824d (2006); 18 CFR 35.13 (2010).
---------------------------------------------------------------------------
177. Notwithstanding the flexibility provided for party-specific
negotiations of data reporting requirements, the record in this
proceeding also confirms that some categories of meteorological data
from VERs having wind or solar as the energy source will be relevant to
most, if not all, power production forecasting deployed by a public
utility transmission provider for these resources. Therefore, the
Commission adopts the proposal to require certain categories of
meteorological data from VERs having wind or solar as the energy
source. Specifically, an interconnection customer with a VER having
wind as the energy source must provide, at a minimum, site-specific
meteorological data including: Temperature, wind speed, wind direction,
and atmospheric pressure. An interconnection customer with a VER having
solar as the energy source must provide, at a minimum, site-specific
meteorological data including: temperature, atmospheric pressure, and
irradiance. The exact specifications of data to be provided by the
interconnection customer will remain subject to negotiation between the
parties, which as noted above must take into account the size and
configuration of the VER, its characteristics, location, and its
importance in maintaining generation resource adequacy and transmission
system reliability in its area. It may also include additional
meteorological data commensurate with the power production forecasting
employed by the public utility transmission provider. As with other
data reporting requirements, the public utility transmission provider
may file an unexecuted LGIA pursuant to FPA section 205 seeking to
demonstrate the necessity of requests for additional information if the
parties cannot reach mutual agreement as to the specifications of data
to be provided.\209\
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\209\ Id.
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178. By defining certain categories of data that must be provided,
while leaving the exact specifications of data to negotiation between
the interconnection customer and the public utility transmission
provider, the Commission has sought to balance the competing interests
of clarity and flexibility. The Commission appreciates that defining
all data requirements with precision in this Final Rule might result in
rules that are easier to implement. However, it also could lead to
interconnection customers incurring costs to provide data at a level of
granularity, for example, that is of no use to the public utility
transmission provider given the type of power production forecasting
deployed. By linking the reporting requirements to the data needs of
the public utility transmission provider, the Commission seeks to
facilitate the deployment of power production forecasting without
unduly burdening the interconnection customer.
179. In the Proposed Rule, the Commission included ``cloud cover''
within the categories of data required of interconnection customers
with a VER having solar as the energy source. The Commission agrees
with commenters that the term ``cloud cover'' is imprecise and thus we
modify Article 8.4 of the pro forma LGIA to refer to ``irradiance.''
However, the Commission declines to distinguish between types of
irradiance and also declines to include ``humidity'' in the minimal
categories of data. These additional characteristics may be more
relevant for some types of facilities than others, so we leave to
public utility transmission providers and their interconnection
customers to identify the specifications of data relevant for
reporting.
180. With regard to the frequency and timing of data reporting, the
Commission modifies the Proposed Rule and allows public utility
transmission providers and interconnection customers whose generating
facilities are VERs to negotiate the frequency and timing of data
submittals. The Proposed Rule would have required the reporting of data
at or near real-time. In response, commenters such as AWEA and
Iberdrola note that some power production forecasts use archived time
series data that may be compiled and transmitted to public utility
transmission providers at a significant costs savings when compared to
the ongoing reporting of data at or near real-time, whereas
NorthWestern suggests that data could be provided on a ten-minute or
longer basis. Based on comments received, the Commission concludes it
is more appropriate for the frequency and timing data submittals to be
negotiated by the parties to ensure that the reporting of data is
consistent with the type of power production forecasting being deployed
by the public utility transmission provider. The Commission revises
Article 8.4 of the pro forma LGIA accordingly.
181. In the Proposed Rule, the Commission sought to require the
reporting of forced outages of 1 MW or more for 15 minutes or more. In
response, commenters disagree as to the relevant level of granularity
for outage data. Rather than establish a specific megawatt reporting
threshold or frequency that could result in the reporting of data that
are not used by the public utility transmission provider, the
Commission concludes it is more appropriate for the public utility
transmission provider and interconnection customer to negotiate the
exact specifications of forced outage data to be provided, taking into
account the size and configuration of the VER, its characteristics,
location, and its importance in maintaining generation resource
adequacy and transmission system reliability in its area. As noted in
the Proposed Rule, this will provide the flexibility necessary to
ensure that the reporting of forced outage data is commensurate with
the power production forecasting being employed by the public utility
transmission provider, consistent with any regional practices that may
exist. Therefore, the Commission modifies the Proposed Rule to align
the reporting of forced outages with the power production forecasting
being employed by the public utility transmission provider. The
Commission also declines to adopt alternative minimum thresholds or
pre-define forced outages for purposes of reporting requirements as
requested by some commenters.
182. Some commenters request that the Commission standardize
protocols for reporting meteorological or forced outage data required
by this Final Rule. The Proposed Rule did not contain standard
protocols for data reporting and, as a result, the merits of such a
requirement have not been fully addressed in the record. Whether
standardization of data communications would facilitate or hinder
development of power production forecasting may implicate a variety of
data and communications issues that would benefit from broad industry
input through standards development processes such as those used by
NAESB and other organizations.
d. LGIA
183. In order to effectuate the reporting requirements discussed
above, the Proposed Rule set forth amendments to the pro forma LGIA
adding a new section Article 8.4, Provision of Data from a Variable
Energy Resource.
[[Page 41513]]
Consistent with the approach of Order Nos. 2003 and 661,\210\ the
Commission proposed not to require retroactive changes to LGIAs that
are already in effect. However, the Commission sought comment as to
whether this approach would prevent public utility transmission
providers from effectively implementing power production
forecasting.\211\ The Commission also preliminarily found that the pro
forma LGIA includes adequate confidentiality protections for sensitive
data obtained from VERs.\212\
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\210\ Order No. 661, FERC Stats. & Regs. ] 31,186 at P 120;
Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
\211\ See Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 64.
\212\ Id. P 60 (citing Pro Forma LGIA Article 22, which sets
forth the confidentiality provisions applicable to data exchanged
through the interconnection process).
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184. The Commission noted that it was proposing revisions only to
interconnection customers whose generating facilities are VERs greater
than 20 MW and, as a result, proposing revisions only to the pro forma
LGIA and not the pro forma Small Generator Interconnection Agreement
(SGIA). The Commission sought comment on whether the proposed reforms
should also apply to interconnection customers whose generating
facilities are VERs of 20 MW or less, so as to require revisions to the
pro forma SGIA.
e. Comments
185. The Commission received a variety of comments on its proposal
to not require retroactive changes to LGIAs that are in effect.
NaturEner argues that without data from existing resources, power
production forecasts would be less reliable or robust, resulting in
artificially high required reserves and attendant expenses. AWEA, Clean
Line, and Iberdrola state that they would not oppose requiring data
from resources that have executed an LGIA, provided that the
interconnection customers are only required to report data that are
currently gathered by the VER. AWEA explains that data already are
being collected by many wind plants deployed since 2005 and that many
public utility transmission providers have already imposed reporting
requirements. However, Southern MN Municipal asserts that the proposed
reforms should not be extended to resources that have already executed
an interconnection agreement. Bonneville Power asserts that Articles
9.3 and 9.4 of the LGIA give the transmission provider a unilateral
right to update its instructions and operating protocols and procedures
regardless of whether the proposed Article 8.4 is applied
retroactively.
186. Midwest ISO Transmission Owners request that the Commission
address the circumstances under which a VER with an existing
interconnection agreement might become subject to the new power
production forecasting requirement if it is applied prospectively.
Midwest ISO Transmission Owners state that, at the very least, any
increase in a facility's generating capacity or material modification
that would necessitate a new LGIA should be sufficient to subject the
VER generator to the new power production forecasting-related data
requirements under the applicable tariff.
187. Some commenters suggest implementing reporting requirements
for meteorological and forced outage data through the pro forma OATT in
order to impose those requirements on existing resources or otherwise
allow for changes in reporting requirements over time.\213\ AWEA
contends that, if the Commission determines to apply the reporting
requirements to existing resources, it would be more appropriate to
place the requirements in the pro forma OATT. Sunflower and Mid-Kansas
agree, noting that the pro forma LGIA already requires parties to
operate their facilities consistent with Applicable Laws and
Regulations, including OATT requirements. Large Public Power argues
that it is important that all VERs provide the operational information
required by a transmission provider and, therefore, also recommends
placing reporting requirements in the transmission tariff. Southern
California Edison contends that placing reporting requirements in the
pro forma OATT would allow greater flexibility in structuring
agreements by referencing requirements in the California ISO Tariff, as
they may change from time to time.
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\213\ E.g., AWEA; Large Public Power; Southern California
Edison; Sunflower and Mid-Kansas.
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188. Other commenters ask the Commission to allow reporting
requirements to be stated in market rules or business practices.\214\
ISO New England requests that the Commission afford flexibility for
public utility transmission providers to determine the mechanism by
which to collect the required VER data. National Grid states that
rather than requiring a proscriptive amendment of the pro forma LGIA,
the Commission should require each region to work with its stakeholders
to develop appropriate methods for forecasting the energy output from
VERs. Pacific Gas & Electric requests that in its Final Rule the
Commission provide latitude for the California ISO and other similarly-
situated transmission providers to continue their existing programs for
gathering relevant meteorological and operational data, and proposing
incremental refinements to them, so long as they conform to the
purposes of the Final Rule. Xcel similarly argues that the specific
data requirements for individual public utility transmission providers
should be identified through a business practice or other OASIS posting
to allow adjustments due to changing system operating needs,
improvements in meteorological forecasting technologies, or
modifications in NERC reliability requirements.
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\214\ E.g., California PUC; Dominion; ISO New England; National
Grid; Pacific Gas & Electric.
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189. With regard to the Commission's question as to whether the pro
forma SGIA needs to be revised, many parties argue that the provision
of data under the SGIA may be appropriate in some instances.\215\ PJM
and Snohomish County PUD note that the costs of reporting the proposed
data to public utility transmission providers by small VERs could be
higher than for larger resources. As such, they argue that the
Commission should carefully consider these costs when applying
reporting requirements. Several other commenters acknowledge
difficulties associated with gathering data from resources subject to
the SGIA, and propose a variety of thresholds to determine whether
reporting requirements should apply to the resource.\216\ For example,
AWEA states that it makes sense to apply similar data reporting
requirements to smaller-scale generators where it can be demonstrated
that the data will be used for improving VER forecast accuracy and that
the benefits exceed the cost of data collection. Others state that
small resources should use alternative reporting requirements.\217\
Southern California Edison recommends that the Commission consider an
approach that aggregates individual site data from small generators in
a geographic area, which reduces cost impacts to smaller projects.
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\215\ E.g., California ISO; EEI; Duke; ISO New England;
MidAmerican; NRECA; Pacific Gas & Electric; PNW Parties; Snohomish
County PUD; Southern California Edison; Tacoma Power; Xcel.
\216\ E.g., AWEA; RenewElec; SEIA; Tacoma Power; Xcel.
\217\ E.g., Alstom Grid; RENEW.
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190. Commenters contend that the public utility transmission
provider should have the flexibility to identify and require data from
small
[[Page 41514]]
generators.\218\ For example, Bonneville Power argues that the
Commission should require small VERs to provide meteorological and
operational data according to the requirements established by their
public utility transmission provider. These commenters generally agree
that public utility transmission providers may have different
forecasting needs, and that they require flexibility to address such
issues. NextEra argues that there is no convincing reason to limit the
forecasting requirement to resources larger than 20 MW, and that the
impact of small VERs on system variability is the same as resources
greater than 20 MW. Midwest ISO Transmission Owners note that the
Midwest ISO pro forma Generator Interconnection Agreement (GIA) applies
to all interconnection customers, regardless of size, and as a result
any reporting requirements adopted in the GIA should apply to
generators with a capacity of less than 20 MW. California PUC asks that
the Commission make clear that public utility transmission providers
are not prohibited from requesting meteorological and operational data
from small VERs. Environmental Defense Fund states that the Commission
should host a technical conference to examine issues arising from
requiring small generators to contribute information to support power
production forecasting.
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\218\ E.g., Bonneville Power; Idaho Power.
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191. Some commenters address other aspects of the Commission's
proposal to amend the pro forma LGIA. AWEA questions the Commission's
preliminary conclusion that the LGIA provides sufficient
confidentiality protection for sensitive operational and meteorological
data, stating that vendors providing forecasts to public utility
transmission providers must not be allowed to use the data they collect
for developing forecasts for the public utility transmission provider
for any other purpose without express agreement. MidAmerican asks the
Commission to clarify that there will not be any additional penalties
for failure to provide accurate meteorological and operational data,
other than the contractual remedies for breach already provided for in
the pro forma LGIA. MidAmerican states that it recognizes that
meteorological data are not always available if, for example,
communication from a collecting device is interrupted. RenewElec
recommends that the Commission set forth a data retention requirement
in the new pro forma LGIA Article 8.4 that would require public utility
transmission providers to maintain data collected from interconnection
customers whose generating facilities are VERs for at least 10 years,
facilitating follow-up studies to update power production forecasts.
f. Commission Determination
192. The Commission affirms the Proposed Rule and amends the pro
forma LGIA to include a new Article 8.4 setting forth the reporting
requirements adopted in this Final Rule. The Commission directs all
public utility transmission providers to file a revised pro forma LGIA
within 12 months of the effective date of this Final Rule reflecting
the revisions adopted herein. As noted below, public utility
transmission providers that have already implemented meteorological or
forced outage reporting requirements may seek to demonstrate, on
compliance, that these existing business practices and market rules
adequately satisfy the requirements of this Final Rule.
193. As set forth in the Proposed Rule, Article 8.4 of the pro
forma LGIA did not state where the meteorological and forced outage
data reporting requirements would be specified in an LGIA. The
Commission agrees with Bonneville Power that it is appropriate to state
reporting requirements for meteorological and forced outage data in
Appendix C, Interconnection Details, as this will allow the
requirements to be changed from time to time. The Commission therefore
revises proposed Article 8.4 to specify that reporting requirements for
meteorological and forced outage data would be set forth in Appendix C,
Interconnection Details, of an LGIA. A transmission provider with an
executed LGIA that seeks reporting of such data may negotiate revisions
to Appendix C related to such reporting requirements with the
interconnection customer. To the extent the parties mutually agree on
changes to Appendix C, such changes to Appendix C need not be submitted
to the Commission for review. If the parties are unable to reach
agreement on proposed modifications to Appendix C, however, these
parties may invoke their rights, as relevant, to modify the LGIA under
sections 205 or 206 of the FPA, as appropriate, and pursuant to Article
30.11 of the LGIA.
194. The Commission disagrees with commenters suggesting that
flexibility provided by business practices or market rules makes them a
superior alternative for implementing the meteorological and forced
outage reporting requirements adopted in this Final Rule. The
Commission has sought to address public utility transmission providers'
need for flexibility by clarifying that reporting requirements are to
be set forth in Appendix C to the LGIA, while also addressing
interconnection customers' need for certainty in the obligations placed
on them. The Commission appreciates that public utility transmission
providers in some regions, including RTOs and ISOs, have already
implemented meteorological or forced outage reporting under business
practices and markets rules. Such public utility transmission providers
may seek to demonstrate in their compliance filing how continued use of
these existing business practices and market rules is adequate to
satisfy the requirements of this Final Rule using the independent
entity variation standard set forth in Order No. 2003, if relevant, or
by demonstrating variations from the pro forma OATT are consistent with
or superior to the requirements of this Final Rule.\219\
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\219\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 9-10.
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195. The Commission declines to modify existing LGIAs already in
effect to include Article 8.4 of the pro forma LGIA as adopted in this
Final Rule. The Commission acknowledges that, in some situations, there
may be a sufficient amount of VERs already interconnected to the public
utility transmission provider's system to make data from those
resources useful or even necessary to properly implement power
production forecasting. However, several considerations lead us to
decline to modify every LGIA in effect on a generic basis. First the
Commission believes retroactive changes to every LGIA in effect could
be administratively burdensome to public utility transmission providers
and interconnection customers, especially where the public utility
transmission provider is not engaged in power production forecasting.
Second, we note that nothing in the pro forma LGIA precludes the
parties to an LGIA from mutually agreeing to revise the requirements
set forth in Appendix C to reflect the reporting of meteorological and
forced outage data. Indeed, we note that Article 9.4 of the pro forma
LGIA recognizes that Appendix C will be modified to reflect changes to
the interconnection customer's requirements as they may change from
time to time. Finally, if the parties are unable to agree to
modifications of Appendix C, we note that pursuant to Article 30.11 of
the pro forma LGIA, the transmission provider has the right to make a
unilateral filing to the Commission proposing to modify an
[[Page 41515]]
existing LGIA under section 205 of the FPA.
196. For similar reasons, the Commission declines suggestions to
implement data reporting requirements through the pro forma OATT
instead of the pro forma LGIA or to include the requirements in the pro
forma SGIA. The effect of relying on the pro forma OATT would be to
impose the data reporting requirements adopted in this Final Rule on
existing interconnection customers retroactively, including those with
resources under 20 MW that are subject to the pro forma SGIA. Like data
from existing resources, data from small resources may be useful or
necessary for power production forecasting, yet the record in this
proceeding does not demonstrate that the need for data from small
resources is so great as to outweigh the potential burden that
reporting requirements could impose on smaller resources. Just as the
pro forma LGIA provides an opportunity for public utility transmission
providers to mutually agree with interconnection customers regarding
reporting requirements, nothing in the pro forma SGIA precludes the
transmission provider from negotiating with the owners and operators of
small VERs to update their SGIAs to provide for the reporting of
meteorological and forced outage data that are necessary for public
utility transmission providers to employ power production forecasting.
As with the pro forma LGIA, section 12.12 of the pro forma SGIA
provides an opportunity for parties to an SGIA to bring any
disagreement to the Commission for resolution.
197. In response to Midwest ISO Transmission Owners, the Commission
notes that the extent to which a new LGIA is necessitated by a new
Interconnection Request or Material Modification is governed by the pro
forma LGIA and Commission precedent. To the extent a new LGIA is
warranted, the VER interconnection customer would be subject to the
relevant requirements of this Final Rule in effect at the time. Public
utility transmission providers may seek to demonstrate in their
compliance filings how continued use of existing tariffs, business
practices and/or market rules is adequate to satisfy the requirements
of this Final Rule using the independent entity variation standard set
forth in Order No. 2003, if relevant, or by demonstrating variations
from the pro forma OATT are consistent with or superior to the
requirements of this Final Rule.\220\
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\220\ See Id. P 910.
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198. With regard to AWEA's concern regarding the confidentiality of
data, the Commission agrees that meteorological and forced outage data
can be commercially sensitive, but concludes that the Article 22 of the
pro forma LGIA provides adequate safeguards for reported data.\221\ Any
vendor providing forecasts to a public utility transmission provider
would be an agent of the public utility transmission provider subject
to the confidentiality obligations of the pro forma LGIA. With regard
to MidAmerican's concern regarding penalties for failure to provide
accurate meteorological and forced outage data, the Commission notes
that the extent to which penalties beyond those set forth in the pro
forma LGIA might be appropriate for failing to satisfy data reporting
requirements will necessarily depend on the facts and circumstances
surrounding each instance of failed reporting. The Commission
appreciates that unforeseen circumstances may impair an interconnection
customer's ability to report data and that the impact of failed
reporting may in many instances be de minimus. However, it would not be
appropriate for the Commission to conclude generically that in no
circumstance would additional penalties beyond those remedies set forth
in the pro forma LGIA be appropriate for failure to comply with the
data reporting requirements of an executed LGIA.
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\221\ Article 22 of the pro forma LGIA defines Confidential
Information to include, among other things, all information relating
to a Party's technology, research and development, business affairs,
and pricing. Each party to an LGIA must hold in confidence and may
not disclose to any person Confidential Information during the term
of an LGIA and for a period of three years after the expiration or
termination of an LGIA.
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199. Finally, the Commission declines to impose special retention
requirements for reported meteorological and forced outage data as
requested by RenewElec. The time period over which a public utility
transmission provider would need to retain meteorological or forced
outage data will be a function of the type of power production
forecasting being employed by the public utility transmission provider.
2. Definition of VER
a. Commission Proposal
200. In the Proposed Rule, the Commission sought to modify the pro
forma LGIA to include a new definition for Variable Energy Resource in
Article 1. The proposed definition identified a Variable Energy
Resource as a device for the production of electricity that is
characterized by an energy source that: (1) Is renewable; (2) cannot be
stored by the facility owner or operator; and (3) has variability that
is beyond the control of the facility owner or operator.\222\ The
Commission stated that it believed the proposed definition was
consistent with NERC's characterization of variable generation.\223\
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\222\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 64.
\223\ Id. (citing NERC, Accommodating High Levels of Variable
Generation 13-14 (2009), available at http://www.nerc.com/files/IVGTF_Report_041609.pdf).
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b. Comments
201. EEI supports the Commission's proposed definition without
modification. California ISO supports the definition's focus on source
of energy, but suggests that the phrase ``by an energy source that'' be
replaced with ``by a fuel source that.'' California ISO states that
this change would make clear that the three conditions that follow
pertain to the fuel source and not the nature of the facility itself.
202. Other commenters disagree with the focus on the source of
energy, arguing that a VER should be defined by reference to its
operating characteristics, including the ability to control
output.\224\ BrightSource states that this would allow for comparison
between facilities with different fuel sources on standard operational
and reliability time-frames and also avoid confusion about types of
plants that combine renewable and conventional fuel sources, such as
solar-gas hybrids. Joined by SEIA, BrightSource argues that a plant
able to maintain a high level of operational control comes close to
fulfilling the operational characteristics of a non-VER generation and
should be treated as such for purposes of the Proposed Rule's
requirements. NextEra agrees, stating that some resources can control
the variability of their facility by adjusting output through
feathering blades, self-curtailment, or similar measures. SEIA suggests
that the Commission consider alternative criteria that could provide a
distinction between VERs with a high level of control and VERs without
such controls, such as if actual production can remain within some
statistical measure of forecast accuracy during its operating hours.
MidAmerican similarly requests that the Commission adopt a definition
based on physical electrical generation output characteristics rather
than input attributes such as fuel type, suggesting that whether energy
sources qualify as ``renewable'' varies among states that have
developed their own renewable resource regulations.
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\224\ E.g., AWEA; BrightSource; NaturEner; NextEra; RenewElec;
SEIA.
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[[Page 41516]]
203. Several of these commenters question the applicability of the
proposed definition to resources that use energy storage to control
output. NaturEner provides a hypothetical example of a plant coupled
with storage and asks that the Commission provide clarification
regarding the impact of such pairing on capacity reserve obligations.
BrightSource asks the Commission to modify the definition to address
how much storage results in a plant not being considered a VER for
purposes of the Proposed Rule and any future rules. AWEA and NextEra
request clarification that the proposed definition would not prevent
VERs from electing to maintain VER status even if they use energy
storage, other firming technologies, or otherwise have the ability to
adjust output. RenewElec and SEIA argue that, regardless of the
Commission's determination on the storage issue for VERs, such
resources should not be exempt from reporting meteorological data to
their public utility transmission provider. BrightSource and SEIA state
that the applicability of the proposed definition is sufficiently
important that the Commission should consider a technical conference on
the issue.
204. Some commenters focus on the applicability of the proposed
definition to particular types of resources, such as tidal, run-of-
river hydro, conduit hydro, co-generation, or biomass.\225\ Snohomish
County PUD argues that, although such facilities would appear to
satisfy the proposed definition, they should not be required to report
the proposed data to public utility transmission providers because the
data reporting would provide minimal benefit to grid operators while
imposing a significant burden on these resources. Focusing on run-of-
river hydro, Snohomish County PUD contends that whether such a facility
is available at any given moment has no impact on the extent to which a
sudden wind ramp might change production on the grid. NorthWestern and
Pacific Gas & Electric agree, arguing that run-of-river hydro is much
more predictable than wind or solar generation on a short-term basis
and, as a result, there would be little benefit to collecting the
meteorological data from such resources. In contrast, Entergy argues
that the proposed definition and associated reporting requirements
should be imposed on Qualifying Facilities to avoid gaps in forecasting
and to allow public utility transmission providers to accommodate the
variability that exists with both Qualifying Facilities and VERs.
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\225\ E.g., Grays Harbor PUD; NorthWestern; Pacific Gas &
Electric; Snohomish County PUD.
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205. Other commenters question the application of the proposed
definition to solar resources.\226\ California ISO explains that while
solar thermal resources store solar thermal heat, they do not store
solar irradiance itself, which is the energy source for the solar
thermal facility. California ISO asks the Commission to clarify that a
solar thermal facility would fall under the proposed definition.
BrightSource contends that the storage and variability elements of the
proposed definition appear to overlap functionally for a solar thermal
plant, given that variability during the operating day could be
controlled in many ways by the facility. BrightSource requests
clarification regarding whether a VER would have to meet both or just
one of these elements to fall within the definition.
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\226\ E.g., BrightSource; California ISO.
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206. ISO New England and NorthWestern offer opposing views on
application of the proposed definition and associated reporting
requirements on behind-the-meter generation. ISO New England recommends
that all distributed or behind-the-meter generation should be required
to provide to the balancing and transmission entities in its area, at a
minimum, specification of the technology and precise location of the
installed resource so that a forecast of output can be developed on an
aggregate scale to include in the balancing area forecast.
207. California State Water Project argues that its wholesale
participating load resource also meets the definition of a VER.
California State Water Project explains that participating load's
primary purpose is not the provision of services to the grid, but
rather water management, and that the load is subject to variability
for reasons beyond California State Water Projects' control, such as
competing environmental and water management requirements. Accordingly,
California State Water Project requests that consideration be given to
expanding the VERs definition to include large wholesale demand
response resources that bid into markets not through a baseline
mechanism, but rather on a basis comparable to generation.
208. ISO New England requests that the Commission afford
flexibility for entities to use existing, superior definitions of VERs.
The ISO New England Tariff already uses the term ``Intermittent Power
Resources'' for wind, solar, run-of-river hydro and other renewable
resources that do not have control over their net power output. As
such, ISO New England requests that the Commission allow entities to
use existing, superior approaches to the extent these are consistent
with the objectives of the proposed reforms. ISO New England states
that adding another term to its tariff could potentially lead to
confusion, and therefore, argues that the region should be afforded the
opportunity to consider the existing terminology in the ISO New England
Tariff, and determine whether any changes are warranted.
209. Bonneville Power states that, in light of its position that
the pro forma LGIA provides transmission providers with the authority
to update operational requirements for VERs, the Commission's proposed
definition is unnecessary. However, Bonneville Power nonetheless states
that it supports the inclusion of the proposed definition in all new
VER interconnection agreements.
c. Commission Determination
210. The Commission adopts the Proposed Rule's definition of VER
and, accordingly, amends Article 1 of the pro forma LGIA to include the
following definition:
Variable Energy Resource shall mean a device for the production
of electricity that is characterized by an energy source that: (1)
is renewable; (2) cannot be stored by the facility owner or
operator; and (3) has variability that is beyond the control of the
facility owner or operator.
The Commission finds it necessary to define VERs in the pro forma LGIA
in order to identify those resources that are required to provide to
their public utility transmission provider meteorological and forced
outage data necessary to enable the public utility transmission
provider to develop and deploy power production forecasting. The
Commission therefore declines to define VERs by their operating
characteristics as suggested by BrightSource and MidAmerican or by
reference to their lack of ability to store output, self-curtail
production, or otherwise firm deliveries as suggested by BrightSource,
NextEra and others. The Commission also declines to define VERs by
their fuel type as suggested by California ISO, because fuel type is an
unduly restrictive subset of energy type.\227\
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\227\ ``Fuel'' is defined as a material used to produce heat or
power by burning. See Merriam Webster, http://www.Merriam-Webster.com, 2011. (November 4, 2011).
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211. As noted elsewhere in this Final Rule, power production
forecasting
[[Page 41517]]
allows the public utility transmission provider to understand the
characteristics of the input energy source for particular resources, to
use those characteristics to predict how the resources will operate,
and in turn to determine whether and to what degree the public utility
transmission provider will need to reserve capacity to manage
variability in generation output. Therefore, it is the variability of
the energy source, not the operating characteristics of the plant or
nature of output, that are critical to identifying the set of resources
that must be subject to the meteorological and forced outage data
requirements adopted above. Defining VERs by reference to operating
characteristics or level of storage could limit the reporting of data
in ways that undermines that ability of public utility transmission
providers to engage in power production forecasting.
212. The Commission declines to establish an exemption to the data
reporting requirements in this Final Rule for VERs utilizing energy
storage or other firming technologies. Not only would this exemption
inhibit the public utility transmission provider's capacity to predict
how the VER resources will operate, but there is also insufficient
evidence in this record to identify an objective threshold for
exemption. The Commission clarifies that the purpose of this definition
is to identify the resources that are required by this Final Rule to
provide to their public utility transmission provider meteorological
and forced outage data; the purpose is not, as suggested by NaturEner,
to assign capacity reserve obligations or other charges. Nor does this
definition supersede those created by other entities for purposes
outside this rule, such as tax benefit purposes or renewable energy
credits.
213. For similar reasons, the Commission declines to limit the VER
definition in the pro forma LGIA to solar and wind resources so as to
exclude run-of-river hydro, tidal, or other new and emerging VER
technologies. Although the Commission anticipates that public utility
transmission providers initially will engage in power production
forecasting predominantly for wind and solar VERs, we leave to the
public utility transmission providers to determine whether their
individual systems necessitate power production forecasting for other
types of VERs. Categorically excluding other types of resources would
undermine the flexibility being provided in this Final Rule. At the
same time, we decline to establish minimum reporting requirements for
non-wind and non-solar VERs and leave to the public utility
transmission providers and VERs to negotiate what data are necessary
for developing and deploying power production forecasting for these
resources, taking into account the size and configuration of the VER,
its characteristics, location, and its importance in maintaining
generation resource adequacy and transmission system reliability in its
area.\228\ Because such requirements will vary system by system, it is
not necessary to hold a technical conference to explore generic
application of the VER definition as suggested by BrightSource and
SEIA.
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\228\ If parties are unable to reach an agreement the public
utility transmission provider may submit a filing requesting the
data and demonstrating how it will be used for power production
forecasting pursuant to section 205 of the FPA.
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214. In response to California State Water Project, the Commission
clarifies that VERs are not defined herein to include demand response
resources. A demand response resource is not a device for the
production of electricity and, therefore, would not fall within the VER
definition adopted in the pro forma LGIA.\229\ In response to ISO New
England and NorthWestern, the definition potentially could apply to
behind-the-meter generation, although such resources would only be
subject to data reporting requirements adopted in this Final Rule to
the extent they enter into a new LGIA or materially modify an existing
LGIA after the effective date of this Final Rule.
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\229\ A demand response resource may use behind-the-meter
generation, potentially including VERs, to facilitate the provision
of demand response. Such use, however, does not mean that such
behind-the-meter generation is itself a demand response resource.
---------------------------------------------------------------------------
215. ISO New England inquires as to the impact of the VER
definition on other definitions in a public utility transmission
provider's existing tariff. As noted above, public utility transmission
providers that are RTOs or ISOs may seek to demonstrate in their
compliance filing how existing tariffs, business practices or market
rules are adequate to satisfy the requirements of this Final Rule using
the independent entity variation standard set forth in Order No. 2003,
if relevant, or by demonstrating variations from the pro forma OATT are
consistent with or superior to the requirements of this Final Rule.
216. With regard to Entergy's request that the Commission apply the
proposed outage reporting requirement to Qualifying Facilities, we
clarify that the data-reporting requirements under this rule apply to
interconnection customers whose generating facilities are VERs as
defined herein. Specifically, when an electric utility purchases an
interconnected Qualifying Facility's total output, the relevant state
authority exercises authority over the interconnection and the
allocation of interconnection costs. But when an electric utility
interconnecting with a Qualifying Facility does not purchase all of the
Qualifying Facility's output and instead transmits the Qualifying
Facility power in interstate commerce to another purchaser, the
Commission exercises jurisdiction over the rates, terms, and conditions
affecting or related to such service, such as interconnections.\230\
Thus, for a Qualifying Facility that is a VER, when the interconnected
Qualifying Facility is selling its total output to an electric utility,
the meteorological and forced outage reporting requirements of this
Final Rule do not apply. However, when an electric utility
interconnecting with a Qualifying Facility does not purchase all of the
Qualifying Facility's output and instead transmits the Qualifying
Facility power in interstate commerce to another purchaser, the
meteorological and forced outage reporting requirements of this Final
Rule are applicable.
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\230\ Order No. 2003, FERC Stats. & Regs. ] 61,103 at P 813. The
Commission regulations governing the exemptions enjoyed by
Qualifying Facilities are codified at 18 CFR Part 292, Subpart F (18
CFR 292.601-292.602 (2011)). Limited exemptions from sections 205
and 206 of the FPA apply to certain sales of energy and capacity
made by Qualifying Facilities. See also Terra-Gen Dixie Valley, LLC,
132 FERC ] 61,215, at PP 45-46 (2010).
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3. Data Sharing
a. Commission Proposal
217. In the Proposed Rule, the Commission sought comment on whether
public utility transmission providers should be allowed or required to
share VER-related data received from interconnection customers with
other entities, like the source or sink balancing authority area for a
transaction, or a government agency, such as NOAA, assuming
confidentiality is protected.\231\
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\231\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 63.
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b. Comments
218. Clean Line and RenewElec state that operational and
meteorological data should be made public to the maximum extent
possible. RenewElec argues that there is a significant lack of
operational data available to researchers in the area of VERs
integration, and asks that the Commission require that: (1) VER data be
made public within six months of the date on which such data is
submitted by the interconnection customer, and (2)
[[Page 41518]]
operational data, including VER data, used by transmission providers to
develop VER power production forecasting be made available to
interested parties.
219. While generally stating support for the sharing of data, some
commenters raise confidentiality concerns and point out the
commercially-sensitive nature of data subject to the reporting
requirements contemplated in the Proposed Rule.\232\ For example,
Southern California Edison supports sharing VER-related data for the
purposes of increasing forecasting accuracy, as long as the data are
not proprietary data that the public utility transmission provider is
prohibited from disclosing to other parties. Bonneville Power and a few
others contend that while sharing data from individual VERs poses
confidentially issues, sharing aggregate VER data does not pose the
same problems.\233\ Sunflower and Mid-Kansas state that, within RTOs,
the stakeholders should decide which entities should be provided VER
data. Western Farmers request that the Commission confirm that, where
the transmission provider is not the balancing authority, the data
should also be provided to the relevant balancing authority. NextEra
and AWEA only support sharing data with other balancing authorities
when the resource is being dynamically scheduled or dispatched into
that balancing authority. Bonneville Power suggests that, at a minimum,
the Commission should allow public utility transmission providers and
balancing authorities to share aggregate forecasts for VER output with
all parties to an e-tag.
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\232\ E.g., CGC; California PUC; EEI; NextEra; PJM; SMUD; ISO
New England.
\233\ E.g., Bonneville Power; California ISO; Exelon; SEIA.
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220. Several commenters support sharing VER-related meteorological
data with NOAA, including having the data incorporated into
foundational models run by NOAA.\234\ Commenters, including NOAA,
request that the Commission require VERs to submit meteorological data
to NOAA for the purpose of improving atmospheric characterization and
forecast accuracy.\235\ In response to confidentiality concerns, NOAA
states that private sector proprietary data can be protected from
distribution and anonymized in the analysis and generation of
forecasts, which would then allow improved predictions to be available
for the private sector to incorporate into power production forecasts.
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\234\ E.g., AWEA; Bonneville Power; CGC; Iberdrola; ISO New
England; MidAmerican; NaturEner; NOAA.
\235\ E.g., Bonneville Power; Iberdrola; NOAA.
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c. Commission Determination
221. The Commission declines to expand the Proposed Rule to require
public utility transmission providers to share VER related data with
other entities such as a balancing authority area or NOAA. However, the
Commission strongly encourages the voluntary sharing of data where
appropriate. Many commenters assert that significant benefits might
flow from VERs sharing data with entities such as a balancing authority
area or NOAA. The Commission finds that VERs are in the best position
to negotiate what data are needed and to weigh the benefits that may be
expected as a result of providing such data. In addition, negotiating
directly with other entities will allow VERs to ensure that adequate
confidentiality protections are in place for information that they may
consider to be commercially sensitive or otherwise confidential. If
helpful to industry participants, the Commission will consider making
staff available to work through issues and, if appropriate, take
additional steps to facilitate the voluntary sharing of information.
4. Cost Recovery
a. Commission Proposal
222. In the Proposed Rule, the Commission refrained from proposing
a single method of cost recovery for the development and implementation
of power production forecasts. Instead, the Commission sought comments
on how public utility transmission providers may recover costs incurred
to develop and deploy power production forecasting tools.\236\
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\236\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 57.
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b. Comments
223. Among those seeking flexibility, AWEA states that the
Commission is correct to not propose a single uniform method for
allocating these costs, and instead should defer to public utility
transmission providers and others to determine how these costs should
be allocated. Several commenters request that the Final Rule provide
flexibility to public utility transmission providers and/or regions to
propose cost recovery approaches.\237\ For example, EEI contends that
generally no interconnected resource should be exempt from the
responsibility for costs that it causes to be incurred, but asks that
the Commission not mandate how costs should be allocated at this time,
allowing regions to develop appropriate cost-recovery solutions.
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\237\ E.g., AWEA; California PUC; Duke; ISO New England;
MidAmerican; Pacific Gas & Electric.
---------------------------------------------------------------------------
224. Some commenters recommend that the cost of forecasting be
spread among all transmission customers.\238\ Independent Power
Producers Coalition-West argues that forecasting tools will ultimately
reduce costs to utilities and generators, and will ultimately be a
small cost of doing business in a world where forecasting can and
should be a constant element of the power scheduling process. Public
Interest Organizations state that the costs of centralized forecasting
infrastructure should be spread across all those who benefit from the
improved accuracy and decreased costs, provided those costs are
demonstrated to be just and reasonable. Joined by NextEra, Public
Interest Organizations argue that the broad benefits of forecasting
justify the sharing of related costs across the transmission system(s)
that benefit.
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\238\ E.g., Iberdrola; Independent Power Producers Coalition-
West; NextEra; Public Interest Organizations; Exelon.
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225. Iberdrola contends that there is no difference in the costs
incurred to develop and deploy power production forecasting tools and
the costs of developing and implementing other market design features.
Iberdrola states that these types of costs typically are not directly
assigned to one set of market participants, but are spread to all users
of the transmission system because they benefit all users of the
system. Iberdrola states that the costs incurred to develop and deploy
power production forecasting tools should similarly be spread to all
system users.
226. Exelon recommends recovering the cost of forecasting within
administrative charges, the approach taken by PJM and ERCOT. Exelon
provides an example of ERCOT's handling of the costs: the cost of
developing the ramp probability tool was a one-time investment that was
recovered by the transmission provider in uplift to the market. The
ongoing cost of using the tool is also spread across the market. Exelon
states that this approach avoids the problem of free-ridership by
future market participants that would occur if these costs were
recovered solely from existing market participants.
227. Other commenters argue either that the VERs, or the
beneficiaries of VERs, should be financially responsible for the costs
of forecasting.\239\ These
[[Page 41519]]
commenters generally contend that public utility transmission providers
should be able to recover the costs incurred to develop and deploy
power production forecasting by imposing a fee or rate upon the VERs
causing the costs to be incurred. For example, NRECA argues that non-
VER transmission customers are neither causing nor benefiting from the
enhancements to power production forecasting and, therefore, should not
be forced to subsidize its costs, citing Northern States Power
Company.\240\ Montana PSC suggests that all VERs of 1 MW or greater
should be responsible for power production forecasting costs. Pacific
Gas & Electric notes the approach taken in the California ISO's
Participating Intermittent Resources Program, in which the California
ISO charges a fee to VERs to recover costs to develop and deploy power
production forecasts.
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\239\ E.g., Bonneville Power; ELCON; Large Public Power Counci;
MidAmerican; Midwest ISO Transmission Owners; Montana PSC;
NorthWestern; NRECA; Oregon & New Mexico PUC; PNW Parties; SMUD;
Southern California Edison; Tacoma Power.
\240\ NRECA (citing N. States Power Co., 64 FERC ] 61,324, at P
63,379 (1993)).
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228. ELCON and Tacoma Power argue that any resource, whether or not
it is a VER, should be held fully accountable for the costs it causes
the transmission provider to incur on its behalf. ELCON argues that
meteorological forecasting is simply a cost of doing business for wind
energy, just as a nuclear power plant must pay for storage of spent
fuel. ELCON argues that these costs should not be recovered in uplift
charges in regions served by ISOs or RTOs, or allocated to non-
customers of VER transactions.
229. SEIA recommends that the Commission examine whether there may
be market entities that would consider contributing to the costs of the
forecast service providers in the non-organized market regions, e.g.,
power traders may be willing to pay for the aggregate day-ahead and
hour-ahead forecasts across such regions. SEIA states that these
revenues could be used to develop aggregated forecasts for more
geographical areas within a region that could further reduce
integration costs.
230. Duke argues that the Commission should allow public utility
transmission providers to update any costs associated with the Proposed
Rule's reporting and power production forecasting requirements without
triggering a general rate case. Duke suggests that one possible option
would be through a formula rate that is updated periodically for
changes in costs related to forecasting and data reporting.
231. Finally, some commenters request that the Commission recognize
that the costs of centralized forecasting go beyond the expense of
forecasting tools.\241\ These additional costs include gathering data,
installing and operating onsite telemetry, equipment to record
meteorological data, and data management. Southern California Edison
points out that data and telemetry are only as good as the personnel
assessing the information.
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\241\ E.g., Pacific Gas & Electric; Southern California Edison;
NorthWestern.
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c. Commission Determination
232. The Commission finds that it is not necessary to prescribe a
single method of cost recovery for developing and implementing power
production forecasting, as it is likely that not all public utility
transmission providers will develop power production forecasting, given
regional differences in the types and penetration of VERs. Moreover,
the record in this proceeding demonstrates that the circumstances under
which a public utility transmission provider may decide to develop and
deploy power production forecasting may vary by system. In some
instances, public utility transmission providers might develop and
employ power production forecasting in order to manage more effectively
the commitment of reserves associated with the provision of generator
regulation service, as discussed in other sections of this Final Rule.
In other circumstances, public utility transmission providers might
develop and employ power production forecasting to manage reserve costs
recovered under other ancillary services. In addition, public utility
transmission providers may seek to recover costs associated with power
production forecasting in different ways, as cost recovery may be
sought via a general rate case, formula rate, or other mechanism. Given
the myriad of factors that may be relevant to the allocation and
recovery of such costs, the Commission finds it appropriate to evaluate
requests for the recovery of costs incurred to develop and deploy power
production forecasts on a case-by-case basis consistent with FPA
section 205 and Commission precedent.
C. Generator Regulation Service-Capacity
233. In the Proposed Rule, the Commission preliminarily found that
clarifying the manner by which public utility transmission providers
may recover the costs associated with fulfilling their obligation to
offer generator regulation service would remove barriers to the
integration of VERs by eliminating public utility transmission
providers' uncertainty regarding cost recovery.\242\ As discussed
below, the Commission concludes that adoption of this reform could
inhibit the flexibility to design capacity services that align with the
operational practices or needs of a particular public utility
transmission provider. The Commission therefore declines to adopt a
generic Schedule 10 for generation regulation service this reform and
instead provides guidance to assist public utility transmission
providers and their customers in the development and evaluation of
proposals related to recovering the costs of regulation reserves
associated with VER integration.
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\242\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 87.
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1. Schedule 10--Generator Regulation and Frequency Response Service
234. In the Proposed Rule, the Commission proposed incorporating
into the pro forma OATT a new ancillary service schedule for Generator
Regulation and Frequency Response Service. The Commission introduced
this proposal with a review of the adoption in Order Nos. 888 \243\ and
890 \244\ of ancillary services schedules for Regulation and Frequency
Response Service (regulation service), energy imbalance service, and
generator imbalance service.\245\ The Commission repeats that
introduction here for background.
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\243\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,703-04.
\244\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 627.
\245\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at PP 66-71.
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235. Regulation service, offered under Schedule 3 of the pro forma
OATT, provides the capacity reserve necessary for the continuous
balancing of resources (generation and interchange) with load to
maintain a scheduled interconnection frequency of 60 cycles per second
(60 Hz).\246\ In Order No. 888, the Commission required public utility
transmission providers to offer regulation service for transmission
service within or into the public utility transmission provider's
balancing authority area to serve load in that area.\247\ However, the
Commission did not require public utility transmission providers to
offer regulation service for transmission service out of or through the
public utility transmission provider's balancing authority area to
[[Page 41520]]
serve load in another balancing authority area.\248\
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\246\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,707-08.
\247\ Id. at 31,717.
\248\ Id.
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236. Energy imbalance service, offered under Schedule 4 of the pro
forma OATT, accounts for hourly energy deviations between a
transmission customer's scheduled delivery of energy and the actual
energy used to serve load.\249\ In Order No. 888, the Commission
required public utility transmission providers to offer energy
imbalance service for transmission service within and into the public
utility transmission provider's balancing authority area to serve load
in that area.\250\ Like regulation service, the Commission did not
require public utility transmission providers to offer energy imbalance
service for transmission service being used to serve load in another
balancing authority area.
---------------------------------------------------------------------------
\249\ Id. at 31,708.
\250\ Id. at 31,717.
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237. Regulation service and energy imbalance service, while
different in function, are complementary services through which public
utility transmission providers maintain their systems' balance and
recover both the capacity (regulation service) and energy (energy
imbalance service) costs of doing so from transmission customers
serving load on their systems. At the time of Order No. 888, the
Commission believed that it was reasonable to provide only standardized
ancillary service schedules for transmission used to service load
because load (rather than generation) exhibited the greatest amount of
variability.\251\ The Commission noted that generators should be able
to deliver scheduled hourly energy with precision and that the
requirements for generators to meet their schedules should be contained
in interconnection agreements.
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\251\ In 1996, when Order No. 888 was developed and issued, wind
generation was not a significant energy source, with a total
capacity of approximately 1,698 MW. See Imbalance Provisions for
Intermittent Resources; Assessing the State of Wind Energy in
Wholesale Electricity Markets, Notice of Proposed Rulemaking, FERC
Stats. & Regs. ] 32,581, at P 7 (2005).
---------------------------------------------------------------------------
238. In Order No. 890, the Commission noted that the existing
energy imbalance charges were the subject of significant concern and
confusion in the industry.\252\ The Commission expressed concern about
the variety of different methodologies used for determining imbalance
charges and whether the level of the charges provided the proper
incentive to keep schedules accurate without being excessive.\253\ Such
concerns led the Commission to revise existing pro forma energy
imbalance service provisions and require public utility transmission
providers to offer a new service, generator imbalance service, to
account for hourly energy deviations between a transmission customer's
scheduled delivery of energy from a generator and the amount of energy
actually generated.\254\ The Commission found that formalizing
generator imbalance provisions in the pro forma OATT would standardize
future treatment of such imbalances, thereby lessening the potential
for undue discrimination, increasing transparency, and reducing
confusion in the industry that resulted from the then current plethora
of different approaches.
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\252\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 634.
\253\ Id.
\254\ Id. P 663.
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239. While the pro forma generator imbalance service provides a
mechanism for public utility transmission providers to recover the cost
of providing the energy needed to manage hourly generator imbalances,
it does not provide a mechanism for public utility transmission
providers to recover the costs of holding reserve capacity associated
with providing generator imbalance energy.\255\ Although the Commission
in Order No. 890 did not create a new rate schedule to expressly
account for these capacity costs, it acknowledged the likelihood that
such costs would be incurred in connection with the provision of
generator imbalance service.\256\ Accordingly, the Commission provided
a mechanism by which public utility transmission providers could
recover these costs, explaining that ``[t]o the extent a [public
utility] transmission provider wishes to recover costs of additional
regulation reserves associated with providing imbalance service, it
must do so via a separate FPA section 205 filing demonstrating that
these costs were incurred correcting or accommodating a particular
entity's imbalances.'' \257\ In Order No. 890-A, the Commission
clarified that public utility transmission providers may propose to
assess regulation charges to generators selling in the balancing
authority area, as well as generators selling outside the balancing
authority area, and that the Commission will consider such proposals on
a case-by-case basis.\258\
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\255\ Id. P 689 (``The Commission concludes that excluding
additional regulation costs as a general matter is appropriate
because much of those costs would be demand costs.'').
\256\ Id. P 690.
\257\ Id. at P 689 & n.401 (referring to costs associated with
capacity used to provide generator imbalance service that otherwise
are not recovered through Schedule 3).
\258\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 313.
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a. Commission Proposal
240. In the Proposed Rule, the Commission sought to add a new rate
schedule to the pro forma OATT that complements the generator imbalance
service provided under Schedule 9 of the pro forma OATT. The Commission
noted that, in order to meet their obligations to offer generator
imbalance service under Schedule 9, public utility transmission
providers must hold unloaded resources in reserve to respond to moment-
to-moment variations attributable to generation. The Proposed Rule
recognized this de facto obligation and proposed to establish a generic
rate schedule (Schedule 10--Generator Regulation and Frequency Response
Service) through which public utility transmission providers may
recover the costs of providing this service. The Commission
preliminarily found that clarifying the manner by which public utility
transmission providers may recover the costs associated with fulfilling
their obligation to offer this service will remove barriers to the
integration of VERs by eliminating public utility transmission
providers' uncertainty regarding cost recovery.\259\
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\259\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 87.
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241. In the Proposed Rule, the Commission stated that Schedule 10
is modeled on Schedule 3--Regulation and Frequency Response Service of
the pro forma OATT. Where Schedule 3 allows public utility transmission
providers to recover the costs of regulation reserves associated with
variability of load within its balancing authority area, proposed
Schedule 10 would provide a mechanism through which public utility
transmission providers can recover the costs of providing regulation
reserves associated with the variability of generation resources both
when they are serving load within the public utility transmission
provider's balancing authority area and when they are exporting to load
in other balancing authority areas.\260\
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\260\ Id. P 88.
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242. The Commission proposed that, consistent with Order No. 890,
public utility transmission providers would not be permitted to charge
transmission customers for regulation reserves under both Schedule 3
and Schedule 10 for the same transaction.\261\ The Commission
[[Page 41521]]
emphasized that in establishing Schedule 10, it was not changing the
nature of the services that a public utility transmission provider must
offer its transmission customers. The Commission stated that nothing in
the Proposed Rule would affect the manner in which balancing
authorities are required to maintain balanced systems that are operated
in a safe and reliable fashion, consistent with NERC Reliability
Standards. The Commission explained that it simply proposed to
establish a generic cost recovery mechanism for a service that public
utility transmission providers already are obligated to offer customers
taking transmission service within their balancing authority area.\262\
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\261\ Id. P 89 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 690 (requiring transmission providers to demonstrate
that any proposals to recover capacity costs associated with
Generator Imbalance Service do not lead to double recovery); Entergy
Serv., Inc., 120 FERC ] 61,042, at PP 62-66 (2007); Sierra Pac. Res.
Operating Cos., 125 FERC ] 61,026 (2008); Westar Energy Inc., 130
FERC ] 61,215, at P 4 (2010)).
\262\ Id. P 91.
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243. In the Proposed Rule, the Commission explained that public
utility transmission providers are not permitted to disclaim the
obligation to offer to provide transmission customers with the capacity
reserves associated with the provision of generator imbalance
service.\263\ Therefore, the Commission proposed that, under Schedule
10, a public utility transmission provider must offer generator
regulation service to the extent it is physically feasible to do so
from its resources or from resources available to it, to transmission
customers using transmission service to deliver energy from a generator
located within the public utility transmission provider's balancing
authority area.\264\
---------------------------------------------------------------------------
\263\ Id. P 84 (citing NorthWestern, Corp., 129 FERC ] 61,116,
at P 27 (2009)).
\264\ Id. P 89.
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b. Comments
i. Proposed Schedule 10
244. Although several commenters support the Commission's proposal
to establish a schedule for the recovery of capacity costs for
regulation reserves, much of that support is tempered by concern about
the scope and design of proposed Schedule 10, as well as the
flexibility afforded public utility transmission providers to design
services relevant to recover all costs associated with the integration
of VERs under proposed Schedule 10.\265\ For example, while EEI
indicates that it supports the establishment of a cost recovery
mechanism for regulation reserves from transmission customers as
promoting rate certainty and transparency, it also cautions the
Commission that the proposal may unduly condition cost recovery and may
not encompass all cost incurred by the transmission provider. While
Independent Power Producers Coalition--West supports the concept of a
generic generator imbalance tariff to bring certainty to disparate
tariffs that must now be negotiated in WECC, it contends that the
Commission should require utilities to revise operating agreements,
business practices or other procedures such that independently owned
generator resources are available to balancing authorities in the WECC
to reduce generator imbalance costs for VERs. Large Public Power
Council supports the new Schedule 10 provided it is implemented in a
way that allows transmission providers to receive full compensation for
providing the service.
---------------------------------------------------------------------------
\265\ CMUA at 10-11; EEI at 25-33; Midwest ISO at 14; NRECA at
23-24; Organization of Midwest ISO States at 8-9.
---------------------------------------------------------------------------
245. NRECA indicates that it also supports the cost recovery
proposal embodied in proposed Schedule 10; however, it expresses
concern that Schedule 10 should not be limited to just the recovery of
regulation costs, and should instead be expanded to allow public
utility transmission providers the opportunity to demonstrate that
additional VER integration costs should be recovered through individual
Schedule 10s. According to NRECA, such costs may include the following:
(1) Intra-hour schedule implementation costs; (2) power production
forecasting implementation costs; or (3) other various costs such as
load-following service, ramping costs, out-of-merit dispatch costs, and
additional spinning and supplemental reserves, among other things.
246. Public Power Council and Puget express similar concerns that
the proposed Schedule 10 would not allow for full recovery of all costs
of balancing and integrating VERs. According to Public Power Council,
Schedule 3 recovers the costs of balancing reserves deployed for
frequency and regulation control, which in turn leads Schedule 10 to
only recover the costs of regulation (capacity following near
instantaneous changes in generation) but not the costs arising from
either load following capacity (capacity used minute-to-minute over
approximately a 10-minute period) or capacity needed to make up a
variable generator's schedule error for the scheduling period. Public
Power Council also argues that Schedule 10 charges should include the
costs of power production forecasting systems as these would not be
needed but for the integration of variable generation. The PNW Parties
agree and suggest that Schedule 10 should be expanded further to allow
for the recovery of all costs incurred by the public utility
transmission provider in providing regulating reserves that are not
recoverable through the generation imbalance rate, including but not
limited to, extra energy costs and operation and maintenance costs.
247. Southern states that the capacity required to provide
generator imbalance service or otherwise respond to operational
challenges presented by substantial swings in output from generators
(particularly VERs) may mostly be conceptualized as providing a
``regulation'' service, but it should be understood that some public
utility transmission providers may also incur additional costs that may
implicate other ancillary services, such as reactive power and load
following, if not contingency response. Southern asserts that the
Commission should not categorically foreclose or limit in advance the
right of public utility transmission providers under section 205 to
file tariffs or tariff amendments on a case-by-case basis to recover
any and all additional reasonable costs specific to VER-related
regulation reserve requirements. Southern requests that the Commission
confirm that the invitation in Order No. 890 for public utility
transmission providers to file rate schedules and amendments to address
costs of generator imbalances on a case-by-case basis remains open.
248. Public Interest Organizations contend that it may be unjust
and unreasonable to charge VERs regulation rates for capacity
requirements that can be addressed by less expensive ancillary
services. Public Interest Organizations state that the Commission could
address this problem either by reforming Schedule 10 into a slower
service akin to load-following or non-spinning reserves, or by
clarifying that Schedule 10 is designed to compensate only for the
moment-to-moment balancing associated with generation variability, and
not for VER variability that affects the system beyond the balancing
timeframe.
249. AWEA suggests that the Commission focus on such longer-term
variability, requesting that the Commission reformulate proposed
Schedule 10 as a system non-spinning service to accommodate the
aggregate system variability that is not accommodated through other
ancillary services. AWEA states that this type of service would benefit
all users of the system by providing inexpensive reserves to
accommodate all types of gradual variability on the power system,
including changes driven by inaccurate
[[Page 41522]]
load forecasts, changes in demand driven by large electricity users, as
well as aggregate changes of many small users. AWEA notes that wind and
solar exhibit little variability over the regulation time period while
variability over the course of an hour can be more significant. AWEA
argues that a system non-spinning service would be well-suited for
accommodating the incremental increase in system variability caused by
the addition of such resources.
250. Similarly, Iberdrola recommends the Commission structure
Schedule 10 as a following reserves service rather than regulation
reserve, arguing that the rate of change associated with wind ramps is
not instantaneous but rather occurs over longer time periods within the
hour and often for multiple hours. To the extent that the Commission
does not reformulate Schedule 10 in this way, Iberdrola requests that
the Commission convene a technical conference that focuses on the
ancillary services needed to support VERs. NextEra agrees that the
Commission should convene a technical conference to address what kind
of ancillary services should be developed to complement the growth of
VERs, among other things.
251. Duke suggests that the Commission should unbundle regulation
and frequency response service into separate ancillary service
schedules. In support, Duke points to such industry activities as NERC
developing a revision to Frequency Response Reliability Standard BAL-
003-0, which will prescribe specific amounts of frequency response that
each balancing authority must procure; the Commission report prepared
by the Lawrence Berkeley National Laboratory, which discusses
operational characteristics and distinctions of primary and secondary
frequency control reserves (Docket No. AD11-8-000); and the
Commission's Notice of Proposed Rulemaking in Docket Nos. RM11-7-000
and AD10-11-000, which also distinguishes frequency response from
regulation.
252. American Clean Skies argues that the Proposed Rule should
require RTOs to offer additional ancillary services, such as load
following (on a minute-to-minute basis), reactive power and other
comparable backup capabilities. Coalition for Green Capital similarly
asks the Commission to encourage the development of power and ancillary
services products that match the technical and commercial capabilities
of VERs to allow VERs to integrate into the bulk power grid at rates
and on terms and conditions that are just and reasonable and not unduly
discriminatory or preferential. Independent Energy Producers assert
that, while it is critical that ancillary service products be
identified and developed to permit VERs to be integrated, it is equally
critical that the necessary compensation measures be developed to
ensure that dispatchable generation is available when and where it is
needed to support the ancillary services products, particularly within
the California ISO market.
253. With regard to charging transmission customers under both
Schedule 3 and the proposed Schedule 10, Bonneville Power agrees with
the Commission's decision in Order No. 890 regarding the potential for
double recovery if energy settlement charges (under Schedules 4 and 9
of the OATT) are imposed on both the generator and load when they
reside in the same balancing authority, but argues that there are
significant differences between energy settlement charges and capacity
charges recovered under Schedule 3 and Proposed Schedule 10. Bonneville
Power states that the public utility transmission provider must
maintain balancing reserve capacity for movement of both the load and
the generators located in its balancing authority area because the
deviations from schedule for the load and generation move independently
from one another, and that the transmission provider should be allowed
to recover costs for capacity it is providing to both generation and
load.
254. Duke similarly argues that the Commission should allow the
public utility transmission provider to recover both Schedule 3 and 10
costs if both services are utilized by the transmission customer. Duke
contends that it is appropriate in some circumstances to charge a load
for Schedule 3, and a generator for Schedule 10, even if they are owned
by the same party. According to Duke, unless the generator is coupled
to the load by an energy management system (i.e., the generator is
controlling to the load), or the generator is dynamically serving a
load (i.e., where its output can be controlled to match the load it
serves), a public utility transmission provider should be permitted to
charge for both Schedule 3 and Schedule 10 as they are two different
services which can be provided at the same time (e.g., where a load
serving entity owns load within a control area, as well as a
generator).
255. Finally, several commenters contend that Schedule 10 is not
necessary in organized markets.\266\ PJM interprets Schedule 10 as
optional and seeks clarification that this interpretation is correct.
Sunflower and Mid-Kansas submit that the SPP market rules already are
consistent with or superior to the pro forma OATT as the Commission
proposed to amend it in the Proposed Rule and believes it is highly
likely that all of the other RTOs' rules are also superior to what has
been proposed. Clean Line contends that the potential of double
recovery exists for generators receiving compensated through organized
market mechanisms. AWEA contends that the Commission should clarify
that the creation of Schedule 10 service should apply only in areas of
the country that do not have functioning ancillary services markets.
Likewise, Iberdrola explains that a Schedule 10-type product is not
necessary in organized markets, as most organized markets balance the
system's energy and reserve requirements through use of simultaneously
co-optimized Security Constrained Unit Commitment and Security
Constrained Economic Dispatch algorithms that clear and dispatch energy
and reserves.
---------------------------------------------------------------------------
\266\ E.g., AWEA; California ISO; Iberdrola; ISO New England,
New York ISO; Sunflower and Mid-Kansas.
---------------------------------------------------------------------------
ii. Obligation To Offer Generator Regulation Service
256. Several commenters seek clarification regarding the extent to
which the public utility transmission provider must provide generator
regulation service. NaturEner states that public utility transmission
providers should not be able to avoid providing regulating reserves
based upon claims that they themselves do not own generation in
sufficient amounts to supply the service. Xtreme Power asks that the
Commission make clear that, in the event that a public utility
transmission provider's existing resources are not adequate to meet the
obligation to provide generator regulation service and new resources
are needed to accommodate additional variability, the public utility
transmission provider is obligated to procure a sufficient quantity of
the appropriate resources.
257. Grant PUD asks whether a public utility transmission provider
must procure additional regulation resources if the demand for these
services exceeds the contractual and owned resources available to the
public utility transmission provider that can provide regulation
service at the time of the request for service. NorthWestern requests
that the Commission clarify
[[Page 41523]]
that the phrase ``or from resources available to it'' refers to
acquisition of generator regulation service from third parties and is
not intended to mean that, if the utility does not have access to its
own resource or resources from the market, the utility must build
generation for Schedule 10 service. Independent Power Producers
Coalition--West states that transmission providers should not be
permitted to charge VERs for generator imbalance services unless they
provide VERs with the capability to obtain those services from third
parties on a non-discriminatory basis. If a public utility transmission
provider does not have access to its own resources or resources from
the market and chooses to build new generation to offer Schedule 10
service, EEI asks the Commission to clarify that these costs can be
recovered from the resources that trigger the need to build. EEI also
states that the language ``or from resources available to it'' could be
read to require the public utility transmission provider to violate
reliability standards by using resources set aside for contingency
reserves to support generation regulation service.\267\ EEI requests
that the Commission clarify the statement as follows: ``a public
utility transmission provider must offer generator regulation service;
to the extent it is physically feasible to do so from its existing
resources or from resources currently available to it, without
violating applicable reliability standards.'' \268\
---------------------------------------------------------------------------
\267\ EEI at 32.
\268\ Id.
---------------------------------------------------------------------------
258. Puget asks that the Commission clarify that public utility
transmission providers are only required to provide Schedule 10 service
within a defined confidence interval commensurate with the public
utility transmission provider's level of regulation capacity set aside
for cost recovery under the Schedule 10. If those resources'
capabilities are exceeded or if system conditions otherwise warrant,
Puget suggests that the public utility transmission provider should
retain the right to curtail generation production or export schedules
to preserve reliability. Public Power Council and Bonneville Power also
question whether the obligation to provide generator regulation service
is unlimited, suggesting that such service could require firming of
every generation delivery, which would be extremely expensive.
Bonneville Power contends that the source balancing authority should
have the ability to offer a base level quantity of balancing reserve
capacity and should have the right to use operational tools to limit
the deployment of reserves to that quantity. In support, Bonneville
Power explains that it has developed Dispatcher Standing Order 216 (DSO
216) to require reductions in wind generation or changes to wind
generators' transmission schedules when the schedule error of the wind
fleet exhausts the total amount of balancing reserve capacity that
Bonneville Power has made available for wind and load.
259. Bonneville Power states that it is currently providing enough
balancing reserve capacity to meet the needs of the wind fleet in its
balancing authority during 99.5 percent of the forecast VER variability
events. Bonneville Power describes the remaining 0.5 percent as
representing the most extreme variability in VER generation (i.e.,
``tail events''). Because of the substantial wind generation exports
from Bonneville Power's balancing authority area, Bonneville Power
explains that it needs a mechanism to ``clip the tails'' of wind ramps
when they exhaust the total amount of balancing reserve capacity that
Bonneville Power makes available for wind and load. Bonneville Power
states that DSO 216 allows it to establish the amount of balancing
reserve capacity that will be deployed and, because there is a set
limit, it is able to quantify its obligation and risks for rate
setting, system planning, and reliability purposes. Bonneville Power
contends that a requirement to maintain balancing reserve capacity at
all times to manage tail events would be significantly expensive.
260. Bonneville Power also asks the Commission to clarify that the
public utility transmission provider is required to offer to provide
Schedule 10 service only to the extent it can do so without harming
system reliability or risking non-compliance with state and Federal law
and other non-power requirements that affect system operations.
Snohomish County PUD and Grays Harbor PUD similarly ask the Commission
to clarify that Bonneville Power should not be required to offer
capacity from the Federal System to meet demand for services under
Schedule 10 where that capacity is not available due to statutory and
regulatory obligations that limit the availability of the Federal
System's capacity. Grays Harbor PUD adds that the Commission should
make clear that, during periods when Bonneville Power's system is
limited by statutory and regulatory constrains, it is not ``physically
feasible'' for Bonneville Power to use that capacity to support
integration of VERs and, therefore, during those periods is exempt from
requirements to do so. Bonneville Power further requests that the
Commission clarify that the public utility transmission provider is
obligated to provide generator regulation service pursuant to Schedule
10 and generator imbalance service pursuant to Schedule 9 only to the
extent that balancing reserve capacity is made available pursuant to
Schedule 10. In addition, Bonneville Power suggests that the Commission
should address the pricing policy articulated in the Avista line of
cases, which restricts public utility transmission providers that are
not in organized markets to recovering cost-based rates for ancillary
services, to ensure public utility transmission providers have the
ability to obtain the necessary balancing reserve capacity.\269\ Tres
Amigas concurs with Bonneville Power and suggests that the Commission
alter its approach so that these services can be bought and sold
competitively outside of organized RTO markets as they are in most
RTOs.
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\269\ Bonneville Power (referencing Avista Corp., 87 FERC ]
61,223 (1999); Market-Based Rates For Wholesale Sales Of Electric
Energy, Capacity And Ancillary Services By Public Utilities, Order
No. 697, 119 FERC ] 61,295 (2007) (Order No. 697)).
---------------------------------------------------------------------------
iii. Self-Supply of Generator Regulation Service
261. First Wind asks the Commission to clarify that Schedule 10
charges would be imposed on VERs only to the degree they take
transmission service or otherwise elect to take Schedule 10 service.
AEP contends that the Proposed Rule contains a loophole in that
purchasers of VER energy outside of the resource's native balancing
authority's footprint would be able to avoid any ancillary service
charges caused by their purchase and transport of energy. Other
commenters discuss how the balancing authority into which generation is
dynamically scheduled would be compensated for providing regulation
service.\270\ These commenters contend that because the sink balancing
authority is providing the regulation service for that generator in
these situations, it should be clear in Schedule 10 that the sink
balancing authority will be paid for providing that service.
---------------------------------------------------------------------------
\270\ E.g., Duke; EEI; Exelon.
---------------------------------------------------------------------------
262. Commenters address the option for transmission customers to
self-supply generator regulation service. Bonneville Power states that
it recognizes that VERs may find it economical to self-supply balancing
reserve capacity to provide balancing service and asks the Commission
to clarify in Schedule 10 that a customer electing to self-supply is
subject to the public utility transmission provider's requirements for
Schedule 10 service
[[Page 41524]]
and the transmission provider's reliability and operational protocols,
including any transmission curtailments and generation limitations in
the event the self-supplying VER fails to meet the transmission
provider's standards. Powerex agrees that the public utility
transmission provider should have discretion to decide whether a method
of self-supply is acceptable but argues that the public utility
transmission provider should be required to describe what it considers
to be acceptable comparable arrangements in posted business practices.
263. Xtreme Power similarly contends that, in order for self-supply
or third-party procurement of generator regulation service to be a
viable option, the public utility transmission provider must specify
how a customer's generator regulation service requirements are
determined and how the requirements may be satisfied through self-
supply or third-party procurement. NaturEner contends that the self-
supply provision should be administered on a flexible basis and this
could include use of self-curtailment, carrying of a portion of the
regulating reserve capacity on a dynamic basis, and carrying of a
varying level of regulating reserves because a constant level is not
necessary. Independent Power Producers Coalition--West argues that
public utility transmission providers should only be permitted to
charge VERs for generator imbalance services if they provide VERs with
the capability to obtain those services from third parties on a non-
discriminatory basis.
264. Beacon Power indicates that entities subject to Schedule 10
should be allowed to work with public utility transmission providers in
non-RTO/ISO markets to determine different volumes of self-supplied
regulation reserve capacity required based on the ramp-rate capability
of its regulation resource(s). CESA agrees that, if a transmission
customer subject to the Schedule 10 chooses to self-supply its
regulation reserve capacity, the amount of capacity self-supplied
should account for the fact that a MW of reserve capacity from a fast-
ramping resource provides more regulation value to the grid per MW than
a slow-ramping resource. NEMA indicates that some resources that
provide generator regulation service, such as batteries and flywheels,
can dampen variations much more quickly than can traditional
generators. Therefore, NEMA contends that the generator regulation
service requirements should be based on the amount of generator
regulation service actually provided, rather than solely the capacity
of regulation service. A123 recommends that the Commission clarify the
phrase ``alternative comparable arrangements'' to include resources
that may differ in MW capacity but supply equivalent or superior
regulation performance when compared to the public utility transmission
provider's default service.
265. Powerex asks that the Commission confirm that self-supply
includes the ability of the transmission customer to self-supply by
purchasing regulation reserve capacity from third parties.\271\ Powerex
states that it could be helpful for the Commission to provide guidance
on what should qualify as an ``alternative comparable arrangement.''
SEIA supports providing transmission customers with the opportunity to
avoid regulation service costs through dynamic scheduling or self-
supply arrangements, but ask the Commission to clarify how self-supply
would allow solar plants to avoid regulation reserve requirements,
which SEIA believes would assign a constantly varying share of the
Schedule 10 requirement to a solar plant capable of providing
regulation service. The Federal Trade Commission asserts that the self-
supply option under Schedule 10 is vague and should recognize that VERs
could address their regulation requirements by matching their
generation variability to demand variability.
---------------------------------------------------------------------------
\271\ Powerex at 22.
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266. Other commenters request that additional requirements be
included in Schedule 10 with regard to self-supply. CGC states that the
Proposed Rule fails to require public utility transmission providers to
provide dynamic transfer capability out of their balancing authority
area or provide an ancillary services market through which a generator
could self-supply generator regulation service. CGC asks the Commission
to require all public utility transmission providers, either by
themselves or in association with other public utility transmission
providers, to provide access to a fully functioning competitive
ancillary services market and/or dynamic transfer capabilities. ELCON
asserts that the Commission should specify that public utility
transmission providers must consider using dispatchable demand response
resources to provide Schedule 10 service. CESA recommends that FERC
allow Schedule 10 self-supply requirements to vary based on the ramp-
rate of the resources providing the service, offering that faster-
acting resources provide more ACE correction than slower resources.
c. Commission Determination
267. The Commission declines to amend the pro forma OATT to include
a standardized ancillary services schedule for generator regulation
services as proposed in the Proposed Rule. As indicated above, the
Commission intended for proposed Schedule 10 to be a clearly defined
mechanism for public utility transmission providers to recover the
costs of capacity held in reserve to provide generator imbalance
service under Schedule 9 of the pro forma OATT, while also providing
customers with certainty as to the rates they will be required to pay
when taking this service. The Commission also sought to confirm the
right of public utility transmission providers to recover the
reasonably incurred costs of providing this capacity service and to
distinguish, where appropriate, among classes of customers who cause
such costs to be incurred.
268. In response to the Proposed Rule, the Commission received
numerous comments urging flexibility in the design of capacity services
needed to integrate VERs into transmission systems, suggesting that the
proposed pro forma generator regulation service may not be the most
efficient and economical service with which to integrate VERs. For
example, Southern notes that the recovery of capacity costs incurred to
provide Schedule 9 generator imbalance service could implicate a range
of services, from regulation to load following, depending on how the
public utility transmission provider conceptualizes the service
provided. Iberdrola suggests that VER integration has more significant
implications for within hour spinning and non-spinning capacity than
moment-to-moment regulation capacity. In light of these comments, the
Commission concludes that the adoption of a standardized pro forma
Schedule 10 could inhibit the flexibility commenters seek to design
capacity services that align with the operational needs of a particular
public utility transmission provider. Accordingly, the Commission
declines to adopt the proposed Schedule 10 component of the Proposed
Rule and will continue to evaluate proposals to recover capacity costs
incurred to provide Schedule 9 generator imbalance service on a case-
by-case basis. In this way, public utility transmission providers will
remain free to propose capacity services that best respond to the needs
of their customers and will not have to expend resources adopting the
one-size-fits-all generator regulation service discussed in the
[[Page 41525]]
Proposed Rule, even in situations where some other service or rate
design may be more appropriate.
269. To be clear, the Commission emphasizes that our decision not
to implement a generic rate schedule for generator regulation service
should not be interpreted as an unwillingness to consider individual
proposals brought by public utility transmission providers. The
Commission recognizes that a public utility transmission provider may
incur capacity costs associated with fulfilling obligations to provide
Schedule 9 generator imbalance service and that existing rate
mechanisms may be inadequate for some public utility transmission
providers to properly allocate and recover those costs. For many years,
the Commission has evaluated proposals to recover such capacity costs
on a case-by-case basis in light of the specific facts and
circumstances in each case.\272\ The Commission concludes that
continuation of this case-by-case approach is more appropriate to
tailor the particular capacity services needed by a public utility
transmission provider to its operations. At the same time, the
Commission is sensitive to commenter requests to provide guidance
regarding the proper design of a generator regulation service charge
should a public utility transmission provider desire to propose one. In
the section that follows, the Commission provides a framework that can
be used for those public utility transmission providers seeking to
develop a proposal to recover capacity costs incurred to provide
Schedule 9 generator imbalance service.\273\
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\272\ See Florida Power Corp., 89 FERC ] 61,263, at 61,765
(1999) (Florida Power) (``The Commission concludes that a generator
imbalance capacity obligation is imposed on the transmission
provider for export transactions, and therefore the Commission
accepts Florida Power Corp's Generator Regulation Service as a
reasonable proposal in those circumstances where the service is not
already covered in an interconnection agreement or a separate
generator tariff.''); Entergy, 120 FERC ] 61,042 at PP 62-66
(accepting a generator regulation service rate schedule for
independent power producers selling out of the control area that
retained charges that had been previously negotiated between Entergy
and the relevant independent power producers); Sierra Pac. Res.
Operating Cos., 125 FERC ] 61,026, at P 10 (2008) (accepting a
generator regulation service rate schedule to provide the capacity
necessary to follow the moment-to-moment changes caused by
generators selling outside of the transmission provider's control
area).
\273\ See infra Sec. IV.C.2 (Mechanics of a Generator
Regulation Charge). While this section is framed primarily in terms
of a generator regulation service, the principles discussed would
also apply more broadly to other capacity services designed to
recover capacity costs incurred to provide Schedule 9 generator
imbalance service.
---------------------------------------------------------------------------
270. Before turning to the mechanics of a generator regulation
service charge, the Commission clarifies in response to comments that
our decision not to adopt a generic Schedule 10 does not relieve public
utility transmission providers of obligations under the pro forma OATT
to provide Schedule 9 generator imbalance service. This in turn
requires the public utility transmission provider to maintain
sufficient capacity to provide that service.\274\ However, as the
Commission explained in Order No. 890-A, if it is not physically
feasible for a transmission provider to offer generator imbalance
service using its own resources, either because they do not exist or
they are fully subscribed, the public utility transmission provider
must attempt to procure alternatives to provide the service, taking
appropriate steps to offer an option that customers can use to satisfy
their obligation to acquire generator imbalance service as a condition
of taking transmission service.\275\ The Commission explained that each
transmission provider can state on its OASIS the maximum amount of
generator imbalance service it is able to offer from its resources,
based on an analysis of the physical characteristics of its system.
Alternatively, a public utility transmission provider may consider
requests for generator imbalance service on a case-by-case basis,
performing, as necessary, a system impact study to determine the
precise amount of additional generation it can accommodate and still
reliably respond to the imbalances that could occur.\276\
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\274\ NorthWestern Corp., 129 FERC ] 61,116, at P 24 (2009),
order denying reh'g, 131 FERC ] 61,202, at PP 17-18 (2010).
\275\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at PP 289-
90.
\276\ Id. P 289.
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271. Because a proposal for generator regulation service would be
associated with generator imbalance service, it follows that the public
utility transmission provider would use a similar analysis to identify
any limitations on its ability to offer either service.\277\ Just as it
can for generator imbalance service, the public utility transmission
provider could explain on its OASIS the maximum amount of generator
regulation service it is able to offer after having attempted to
procure alternative resources to provide the service. Alternatively,
the public utility transmission provider could perform a system impact
study to determine the precise amount of generator regulation service
it can provide. In response to NorthWestern, this Final Rule does not
place any obligation on the public utility transmission provider to
build generation.
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\277\ In the unlikely event that there are no additional
resources available to enable the public utility transmission
provider to meet its obligation to offer generator regulation
service, the public utility transmission provider must accept the
use of dynamic scheduling with a neighboring control area. See id. P
290.
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272. With regard to comments regarding self-supply of ancillary
services, the Commission acknowledges that self-supply may come from
many sources, including purchased capacity and the use of non-
generation resources, as suggested by ELCON. The option to self-supply
certain ancillary services has been in place since Order No. 888, and
the Commission declines here to specify any particular requirements for
self-supply arrangements for generator regulation service proposals. To
do so could restrict flexibility to develop competitively priced
options tailored to particular customer needs. As suggested by some
commenters, such options could include the use of faster ramping
resources to provide the service.
273. In response to Powerex, the Federal Trade Commission and
others, the Commission does not believe that the self-supply option is
vague or that additional guidance is necessary on what should qualify
as an ``alternative comparable arrangement.'' The Commission notes that
public utility transmission providers already are obligated to post on
their public Web sites all rules, standards, and practices, to the
extent they exist, that relate to transmission service.\278\ The
provision of ancillary services is necessary to accomplish transmission
service and, therefore, we conclude this posting obligation applies
equally to ancillary services.\279\ Public utility transmission
providers must post any rules, standards, and practices regarding self-
supply requirements pursuant to their obligation to allow self-supply
of ancillary services.\280\ The Commission declines to adopt further
requirements at this time regarding the self-supply of ancillary
services.\281\
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\278\ Order No. 890, FERC Stats.& Regs. ] 31,241 at P 1652.
\279\ The Commission notes that this obligation is subject to
audit as are all other OATT requirements.
\280\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705.
\281\ Id.
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274. In response to the Federal Trade Commission, the Commission
encourages transmission providers, generators, and transmission
customers to work together to explore options to find the least cost
methods of balancing the system as a whole and to provide maximum
flexibility for products and services that meet the needs of the
customers and the transmission
[[Page 41526]]
providers alike. This includes, for example, evaluating the extent to
which regulation service obligations can be addressed by matching
generation variability to demand variability, as suggested by the
Federal Trade Commission. Indeed, in Order No. 888, the Commission
stated that the pricing of ancillary services should include the amount
of each ancillary service that the transmission customer must purchase,
self-supply, or otherwise procure and must be readily determinable from
the transmission provider's tariff and comparable to obligations to
which the transmission provider itself is subject.\282\ The Commission
also specified that the transmission provider is required to identify
the regulating margin requirements for transmission customers serving
loads in its balancing authority area and to develop procedures by
which customers can avoid or reduce such requirements.\283\
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\282\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,721.
\283\ Id. at 31,717. Order No. 890 did not alter the
requirements of Order No. 888 in this regard, but did clarify that
regulation and frequency response, as well as imbalance energy, may
be provided by public utility transmission providers or through
self-supply using generating units as well as other non-generation
resources such as demand resources where appropriate. Order No. 890,
FERC Stats. & Regs. ] 21,241 at P 888.
---------------------------------------------------------------------------
275. For reasons explained elsewhere in this Final Rule, the
Commission declines to adopt CGC's suggestion to require transmission
providers to provide dynamic transfer capability out of their balancing
authority area or mandate the creation of an ancillary services market
through which a generator could self-supply generator regulation
service.\284\
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\284\ See supra IV.A.1 (Intra-Hour Scheduling Requirement).
---------------------------------------------------------------------------
2. Mechanics of a Generator Regulation Charge
276. The Proposed Rule stated that, as with Schedule 3, the
proposed Schedule 10 charge would be the product of two components: a
per-unit rate for regulation reserve capacity, and a volumetric
component for regulation reserve capacity.\285\ The Commission proposed
to require each public utility transmission provider to submit a
compliance filing that includes the addition of a Generator Regulation
and Frequency Response rate schedule to the OATT that includes the same
per unit rate from their currently effective Regulation and Frequency
Response rate schedule and a blank or unfilled volumetric
component.\286\
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\285\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 92. The
Commission is exploring potential reforms to ancilliary services
pricing in other proceedings. See Third-Party Provision of Ancillary
Services; Accounting and Financial Reporting for New Electric
Storage Technologies, Notice of Proposed Rulemaking, 139 FERC ]
61,245 (2012) (NOPR).
\286\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 101.
---------------------------------------------------------------------------
277. The Commission preliminarily found that the per-unit rate for
service under proposed Schedule 10 should be the same as the rate for
service under existing Schedule 3.\287\ The Commission explained that
Schedule 3 and the proposed Schedule 10 are both designed to recover
the costs of holding regulation reserve capacity to meet system
variability. Because the service provided under both schedules is
functionally equivalent, the Commission proposed to find that it is
just and reasonable to use the same rate currently established in a
public utility transmission provider's Schedule 3 when charging
transmission customers under Schedule 10. The Commission stated that,
for a public utility transmission provider to apply a different rate
under the proposed Schedule 10, the public utility transmission
provider would have to demonstrate that the per-unit cost of regulation
reserve capacity is somehow different when such capacity is utilized to
address system variability associated with generator resources. The
Commission also noted that the use of a common rate is consistent with
Commission policy utilizing the same rate structure for energy and
generator imbalance service, as well as the generator regulation rate
that the Commission accepted in Westar Energy Inc.\288\
---------------------------------------------------------------------------
\287\ Id. P 94.
\288\ Id. P 93 (citing Westar Energy Inc., 130 FERC ] 61,215
(2010) (Westar)).
---------------------------------------------------------------------------
278. With regard to the volumetric component of the Schedule 10
rate, the Commission proposed to provide each public utility
transmission provider with the opportunity to justify a proposal: (1)
To require all transmission customers who are delivering energy from
generators to purchase, or otherwise account for, the same volume of
generator regulation reserves; or (2) to require transmission customers
who are delivering energy from VERs to purchase, or otherwise account
for, a different volume of generator regulation reserves than it
proposes to charge transmission customers delivering energy from other
generating resources.\289\ The transmission provider's proposal would
be made in a section 205 filing after the acceptance of its compliance
filing.
---------------------------------------------------------------------------
\289\ The Commission noted its expectation that, in any
subsequent filing to establish a volumetric component in Schedule
10, public utility transmission providers would address how Schedule
10 and Schedule 3 work together to allow for the recovery of total
regulation reserve costs. Id. P 105 & n.206.
---------------------------------------------------------------------------
279. Where a public utility transmission provider proposes the same
volume of generator regulation reserves for all generators, the
Commission proposed that it demonstrate that the volume of regulation
reserves required of transmission customers delivering energy from
generators located within its balancing authority area be commensurate
with their proportionate effect on net system variability, taking
account of diversity benefits.\290\ The Commission stated that such a
filing must show that the public utility transmission provider has
fully implemented (or been granted waiver from) the intra-hourly
scheduling requirement set forth in the Proposed Rule.\291\ The
Commission recognized that a public utility transmission provider with
few VERs located in its balancing authority area may choose to apply
only one volumetric regulation requirement for all generating resources
in its balancing authority area. The Commission noted that this also
may be the case to the extent the impact of VERs on a public utility
transmission provider's system is minimal and the public utility
transmission provider, in its judgment, deems the administrative burden
of justifying two separate volumetric regulation requirements is
uneconomic.\292\
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\290\ The Commission explained that diversity benefits result
from the aggregation of the variations of all resources such that
one resource's negative deviation can offset some or all of another
resource's positive deviation. The Commission stated that, when the
transactions of two customers result in diversity benefits, it is
incorrect to say that one customer is benefitting the other but not
vice versa. Instead, the Commission preliminarily found that
diversity benefits would result from both transactions and that
sharing of these benefits among the customers would be reasonable.
Westar,130 FERC ] 61,215 at P 37.
\291\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 105.
\292\ Id. P 94.
---------------------------------------------------------------------------
280. The Commission proposed that where a public utility
transmission provider proposes to require transmission customers who
are delivering energy from VERs to purchase, or otherwise account for,
a different volume of generator regulation reserves than it proposes to
charge transmission customers delivering energy from other generating
resources, the Commission proposed that it demonstrate that the volumes
of regulation reserves required of those subsets of transmission
customers delivering energy from generators located within its
balancing authority area are commensurate with their proportionate
effect on net system
[[Page 41527]]
variability and taking account of diversity benefits.\293\ That is, any
proposal for different volumes of generator regulation reserves based
on the generating resource would need to be supported by data showing
that, on the public utility transmission provider's system, VERs have a
different per unit impact on overall system variability than
conventional generating units.\294\ The Commission proposed that such a
filing must also show that the public utility transmission provider has
fully implemented (or been granted waiver from) the intra-hourly
scheduling requirement set forth in the Proposed Rule and has developed
and deployed power production forecasting for VERs.\295\
---------------------------------------------------------------------------
\293\ Id. P 106.
\294\ Id. P 95.
\295\ Id. P 106.
---------------------------------------------------------------------------
281. Specifically, the Commission proposed that any filing by
public utility transmission providers including different volumetric
requirements for different subsets of transmission customers must be
supported with actual data collected over a one-year period subsequent
to the deployment of power production forecasting for VERs and the
implementation of intra-hourly scheduling at 15-minute intervals. The
Commission acknowledged that this proposal could delay a public
utility's ability to recover the cost associated with providing
generator regulation service. The Commission further acknowledged that
there may be alternative methods for developing the data necessary to
support different volumetric requirements for different subsets of
transmission customers. The Commission sought comment as to such
methods of demonstration, how they could support a Commission finding
that the Schedule 10 filing is just and reasonable, and ways in which
these methods of demonstration may be preferable to this aspect of the
Commission's proposal.\296\
---------------------------------------------------------------------------
\296\ Id. P 107.
---------------------------------------------------------------------------
282. In the Proposed Rule, the Commission stated that the increased
use of power production forecasts in transmission systems where VERs
are located can provide transmission providers with improved
situational awareness, enable transmission providers to utilize
existing system flexibility through the unit commitment and dispatch
processes, and, ultimately, lead to a reduction in the amount of
reserve products needed to maintain system reliability. The Commission
also recognized that, in areas of the country with very limited
production from VERs, the implementation of power production
forecasting for VERs could be less useful.\297\ The Commission sought
comment in the Proposed Rule on the manner by which a public utility
transmission provider should be required to show it has developed and
deployed power production forecasts to support a proposal to require a
differentiated volumetric component of rates for generator regulation
reserves under proposed Schedule 10.\298\
---------------------------------------------------------------------------
\297\ Id. P 55 n.125.
\298\ Id. P 106.
---------------------------------------------------------------------------
a. Comments
i. General
283. Invenergy Wind requests that the Commission clarify that, in
requiring initial Schedule 10 charges to adopt the utility's then-
effective Schedule 3 charges, the application of the rate will be
consistent. Invenergy Wind states that Schedule 3 charges are typically
applied on the basis of a percentage of the customer's schedule. Beacon
Power questions the reliance on existing regulation service charges,
stating that a transmission provider in non-RTO/ISO markets could
optimize the performance of its existing fleet to potentially lower
costs to customers under Schedule 3 or 10. Beacon Power requests that
the Commission encourage such transmission providers to evaluate the
technologies and benefits they provide. Xtreme Power agrees, asking the
Commission to require public utility transmission providers to make a
showing that the rates proposed for Schedule 10 are based on an
appropriate type and quantity of resources needed, considering the
technologies available in the market today rather than using dated
rates from Schedule 3. CESA suggests that the reforms proposed for
Schedule 3 in the Commission's Frequency Regulation Notice of Proposed
Rulemaking be included in Schedule 10 for RTO and ISO markets.\299\
---------------------------------------------------------------------------
\299\ CESA; See also Notice of Proposed Rulemaking on Frequency
Regulation Compensation in the Organized Wholesale Electric Markets,
134 FERC ] 61,124 (2010) (Frequency Regulation NOPR); Frequency
Regulation Compensation in the Organized Wholesale Power Markets,
Order No. 755, 76 FR 67260 (Oct. 31, 2011), FERC Stats. & Regs. ]
31,324 (2011), reh'g denied, Order No. 755-A,138 FERC ] 61,123
(2012).
---------------------------------------------------------------------------
284. Some commenters suggest that public utility transmission
providers be permitted to recover opportunity costs associated with
providing generator regulation service.\300\ For example, the Large
Public Power Council states that, consistent with the decision in
Puget, generator regulation service rates should be fully compensatory,
and may legitimately reflect a utility's full opportunity cost.\301\
According to Puget, there may also be lost opportunity costs associated
with reserving unloaded generation capacity during peak market
conditions. NRECA argues the integration of a significant amount of
VERs will cause the Schedule 3 rate to rise as Schedule 10 demand
increases particularly in regions with a lot of hydropower, where the
additional VERs cause the need for more thermal reserves, which are
more expensive than the existing reserve rate base.
---------------------------------------------------------------------------
\300\ E.g., SMUD; WUTC; EEI; Large Public Power Council; Puget.
\301\ E.g., Large Public Power Council (citing Puget Sound
Energy, 132 FERC ] 61,128 (2010)).
---------------------------------------------------------------------------
ii. Quantity of Reserves
285. Some commenters request further direction from the Commission
regarding the calculation of the volumetric component of Schedule 10,
i.e., the quantity of reserves transmission customers are required to
purchase or otherwise account for.\302\ For example, the California PUC
asserts that the Commission should recommend or require that a public
utility transmission provider consider the system's resource mix and
the amount of operational flexibility of the transmission system's
generation fleet to develop the volumetric component of Schedule 10.
LADWP indicates that measures of alleged diversity benefits may lead to
unintended results if significant diversity occurs in one part of a
year and forms the basis for a smaller volumetric component than is
necessary for another part of the year.
---------------------------------------------------------------------------
\302\ E.g., CPUC; LADWP; SEIA.
---------------------------------------------------------------------------
286. Some commenters question whether the Commission should allow
public utility transmission providers the opportunity to file for
differentiated volumetric rates under Schedule 10. AWEA contends that
it would be unjust and unreasonable and break with Commission precedent
to allocate to generators the costs of Schedule 10, whether kept as a
regulation reserve or reformulated to a system non-spin service, while
allocating other ancillary services costs broadly to load. AWEA states
that all users of the grid add variability and uncertainty and that all
benefit when the grid is better able to accommodate variability and
uncertainty. AWEA also argues that the capacity used to provide
Schedule 10 service would be available to provide a number of other
ancillary services, not to mention to the public utility transmission
provider to meet peak demand.
287. Western Grid states that the integration costs of other types
of generation are largely ignored and the
[[Page 41528]]
regulation and frequency costs imposed by large loads are broadly
socialized. Western Grid therefore contends that grid integration costs
related to VERs should be recovered in a manner comparable to the way
grid integration costs imposed by large conventional generators are
recovered. Argonne National Lab argues that calculating the net impact
of VERs on regulation service needs is likely to be difficult and
contentious and that to ensure just and reasonable treatment of all
resources, the Commission should be careful in imposing specific
requirements on VERs without considering the specific impacts on system
reliability and operating reserve costs from other generating resources
as well. Similarly, the Federal Trade Commission recommends that the
Commission consider whether the costs of imbalance services provided to
other types of generators can readily be identified and charged to the
responsible parties.
288. Some commenters support the proposal to condition the
implementation of differentiated volumetric rates on whether that
transmission provider has implemented power production forecasting and
intra-hour scheduling reforms.\303\ AWEA states that Schedule 10 should
not be charged at all until a transmission provider has fully
implemented the Efficient Dispatch Toolkit and the Commission's
proposed sub-hourly scheduling and variable energy forecasting
operating reforms. Clean Line states that implementation of forecasting
should be required before any special charges are assigned to renewable
generators. Clean Line argues that, before transmission providers can
charge a just and reasonable rate to recover ancillary service costs,
they must use reasonable means to minimize those costs--such as
forecasting.
---------------------------------------------------------------------------
\303\ E.g., AWEA; BP Energy; Iberdrola; Independent Power
Coalition West; NextEra; Oregon & New Mexico PUC; Public Interest
Organizations; Vestas.
---------------------------------------------------------------------------
289. Some commenters suggest that differentiated volumetric rates
should be conditioned on implementation of additional reforms beyond
those set forth in the Proposed Rule.\304\ For example, Environmental
Defense Fund maintains that a public utility transmission provider
should not be permitted to establish different volumetric reserve
requirements for VERs unless it has demonstrated to the Commission that
the balancing authority area is optimally sized or cooperating with
other balancing authority areas. Oregon & New Mexico PUC similarly
state that Schedule 10 charges for VERs should be conditioned on a
demonstration by the public utility transmission provider regarding the
measures it has considered to increase cooperation with other balancing
authorities to lower the cost of integrating wind and solar. First Wind
argues that public utility transmission providers should only be
permitted to charge for generator regulation service once they have
implemented procedures for dynamic transfers in addition to intra-hour
scheduling. CESA contends that, before imposing any generator
regulation costs on VERs, public utility transmission providers should
first implement fast intra-hour markets and intra-hourly scheduling; a
robust ancillary services market; the option for third-party or self
supply of ancillary services; dynamic transfer capability out of the
balancing authority area; and Area Control Error (ACE) diversity
interchange or an energy imbalance service market.
---------------------------------------------------------------------------
\304\ E.g., Iberdrola; First Wind; Oregon & New Mexico PUC;
Environmental Defense Fund.
---------------------------------------------------------------------------
290. In contrast, ELCON asserts that Schedule 10 as proposed is a
mechanism for the socialization of costs that should be directly
assigned to VERs or their customers. Grant PUD argues that variable
loads and variable resources should be charged differently for
regulation service according to the nature of the different costs
placed on the public utility transmission provider. A number of other
commenters agree, objecting to any delay in cost recovery associated
with providing generator regulation service.\305\ For example, Pacific
Gas & Electric and Idaho Power argue that public utility transmission
providers incur costs to provide generator regulation service
regardless of whether they are employing intra-hourly scheduling and,
thus, preventing recovery of generator regulation service costs shifts
those costs to other customers in violation of cost causation
principles.
---------------------------------------------------------------------------
\305\ E.g., Tacoma Power; Montana PSC; Pacific Gas & Electric;
PNW Parties; NV Energy; Public Power Council; Natural Gas; WUTC.
---------------------------------------------------------------------------
291. EEI opposes requiring a public utility transmission provider
to commit specific actions before seeking rate recovery under section
205, particularly when such actions violate cost causation principles.
EEI states that as articulated by the Commission in Northern States
Power Company, ``[t]he fundamental theory of Commission ratemaking is
that costs should be recovered in the rates of those customers who
utilize the facilities and thus cause the cost to be incurred.'' \306\
According to EEI, the D.C. Circuit echoed this sentiment in KN Energy,
Inc. v. FERC, ``[s]imply put, it has been traditionally required that
all approved rates reflect to some degree the costs actually caused by
the customer who must pay them.'' \307\ EEI and others state that, to
the extent the Commission conditions generator regulation service cost
recovery on implementing the Proposed Rule's reforms, the Commission
should explain how such a limitation does not effectively force public
utility transmission providers to waive their sections 205 and 206
rights under the FPA in contravention of Atlantic City Electric
Company.\308\
---------------------------------------------------------------------------
\306\ EEI at 29 (citing N. States Power Co., 64 FERC ] 61,324,
at P 13 (1993) (emphasis supplied) (citations omitted)).
\307\ EEI at 29 (citing KN Energy, Inc. v. FERC, 968 F.2d 1295,
1300 (D.C. Cir. 1992); Alcoa Inc. v. FERC, 564 F.3d 1342, 1346 (D.C.
Cir. 2009); Illinois Commerce Commission v. FERC, 576 F.3d 470, 476
(7th Cir. 2009); Pub. Serv. Comm. of Wisc. v. FERC, 545 F.3d 1058,
1067 (D.C. Cir. 2008); Pac. Gas & Electric Co. v. FERC, 373 F.3d
1315, 1320 (D.C. Cir. 2004)).
\308\ EEI at 27-28 (citing Atlantic City Elec. Co., 295 F.3d 1,
10 (2002) (finding that the Commission lacks the authority to
require public utility transmission providers to cede their rights
under section 205 of the FPA); MidAmerican at 26; Puget at 17
(questioning whether whether requiring one-year of data reporting
interferes with a public utility transmission provider's rights
under section 205 of the FPA); WUCT at 7 (questioning whether
requiring 15-minute scheduling and one-year of data reporting
interfere with a public utility transmission provider's rights under
section 205 of the FPA)).
---------------------------------------------------------------------------
292. Southern opposes conditioning public utility transmission
providers' rights to recover rates under section 205 of the FPA for
generator regulation and frequency response service on the
implementation of such reforms. Southern argues that utilities have a
statutory right to establish just and reasonable rates under sections
205 and 206 of the FPA. If the Commission pursues these limitations,
Southern asks the Commission to explain how such a limitation does not
effectively force public utility transmission providers to waive their
section 205 and 206 rights.
293. LADWP argues that the proposed requirements would place public
utility transmission providers in a defensive role. LADWP states that
presuming a public utility transmission provider makes a sufficient
showing that it implemented intra-hour scheduling and deployed power
production forecasting for VERs, a transmission provider is further
compelled to demonstrate the basis for any difference in regulating
reserves between VER transmission customers and non-VER transmission
customers. LADWP argues that this could put the public utility
transmission providers in a defensive role of justifying the findings
and conclusions within a system impact study report, in
[[Page 41529]]
the event performed by the public utility transmission provider.
iii. Power Production Forecasting
294. Some commenters state specific opposition to linking power
production forecasting to the implementation of differentiated
volumetric rates under Schedule 10.\309\ Southern argues the Commission
would exceed its statutory authority if it required implementation of
power production forecasting. Southern states courts have recognized
that the Commission ``is a `creature of statute,' having no
constitutional or common law existence or authority, but only those
authorities conferred upon it by Congress.'' \310\ Southern contends
that, because the FPA never mentions meteorological forecasting, it is
beyond the scope of the Commission's authority. Southern explains that
public utilities have long engaged in meteorological forecasting for
load forecasting and dispatch purposes; however, there never has been
an indication that such practices were within the scope of the
Commission's jurisdiction, and the advent of VER generation has not
added such forecasting to the scope of the Commission's authority.
---------------------------------------------------------------------------
\309\ E.g., Bonneville Power; Montana PSC; Natural Gas; Public
Power Council; Puget Sound Energy; NV Energy.
\310\ Southern (citing Cal. Indep. Sys. Operator Co. v. FERC,
372 F.3d 395, 398 (D.C. Cir. 2004) (citing Atlantic City Elec. Co.
v. FERC, 295 F.3d at 8)).
---------------------------------------------------------------------------
295. While Bonneville Power acknowledges that centralized power
production forecasts will facilitate system-wide benefits, Bonneville
Power disagrees that such forecasts should be a prerequisite to the
cost recovery of balancing reserve capacity used to provide generator
regulation reserve-type services. Bonneville Power believes that such a
requirement would shift costs to other users of the transmission system
that would not be otherwise incurred but for the VER generation. Puget
believes that requiring transmission providers to implement power
production forecasting as a precondition to Schedule 10 cost recovery
inappropriately shifts the costs of integrating VERs from the VER to
the balancing authority. Southern argues that meteorological
forecasting issues are business decisions that are best left to the
transmission providers and the market. EEI states that it is not
convinced that the power production forecasting requirements are
necessary to support requiring a higher volumetric amount of Schedule
10 regulation service. According to EEI, the data necessary to
substantiate a higher volumetric charge can be derived by analyzing the
deviation between a VER's scheduled versus actual production. EEI,
therefore, claims that requiring a public utility transmission provider
to implement power production forecasting prior to establishing a
higher volumetric rate creates a barrier to cost recovery.
296. Montana PSC notes that the Proposed Rule's data reporting
requirements to support power production forecasting would only apply
to generators that are 20 MW or larger. Montana PSC argues that
conditioning differentiation of volumetric rates on the implementation
of power production forecasting could unduly restrict application of
Schedule 10 generation regulation charges to smaller resources. Montana
PSC argues that all VERs one MW or greater should be responsible for
Schedule 10 services that they cause.
297. Other commenters ask the Commission to mandate use of power
production forecasting by all public utility transmission providers
with significant amounts of VERs instead of relying on the public
utility transmission owner's decision to charge differentiated Schedule
10 rates.\311\ The ISO/RTO Council argues that, while transmission
providers in areas with low to moderate levels of VER interconnection
may be able to manage variability on their systems without using power
production forecasting, areas with larger levels of VERs should be
required to adopt power production forecasting tools to ensure that
conditions affecting generation output can be anticipated and managed
appropriately. SEIA suggests that each transmission provider that
provides interconnection to or has interconnections with more than 50
MW of VERs should be required to develop a power production methodology
to accommodate integration of VERs. First Wind contends that power
production forecasting should be mandatory for public utility
transmission providers with five percent of VER resources on their
system. CPUC asks that the Commission clarify that any public utility
transmission provider may require power production forecasting if VERs
are currently or anticipated to become significant.
---------------------------------------------------------------------------
\311\ E.g., CPUC; ISO RTO Council; Midwest ISO; SEIA.
---------------------------------------------------------------------------
298. Some commenters support the Commission's recognition that
certain regions may not have a need for VER power production
forecasting because of a low likelihood of VERs development.\312\ For
example, Bonneville Power states that the requirement to implement
centralized forecasting should not apply if the penetration of VERs is
less than 10 percent of load served. Puget argues that it should not be
required to use power production forecasting because it only serves one
exporting VER in its region.
---------------------------------------------------------------------------
\312\ E.g., Bonneville Power; NextEra; PNW Parties.
---------------------------------------------------------------------------
299. Several commenters provide detailed discussions of the various
activities that public utility providers should be required to
undertake in order to show power production forecasting is in use.
Public Interest Organizations suggest that the Commission require
public utility transmission providers to demonstrate that VER power
production forecasts are incorporated into unit commitment, scheduling,
and dispatch efforts. Oregon & New Mexico PUC state that at a minimum,
a public utility transmission provider needs to demonstrate that it has
requested meteorological and operational data from wind and solar
generators and has integrated forecast information into control room
operations.
300. Some commenters contend that the public utility transmission
provider should demonstrate that it is using the VER forecast to
efficiently and reliably commit and dispatch resources. These parties
offer various criteria regarding costs, accepted industry practices,
and performance metrics that should be required of public utility
transmission providers in order to be deemed compliant with the Final
Rule.\313\ The California PUC states that, while it does not recommend
that the Commission set specific minimum quality standards or cost
maximums for VERs forecasts at this time, the Commission should monitor
results of public utility transmission providers' assessments. If the
quality of forecasts varies significantly among public utility
transmission providers, the Commission may determine that minimum
quality standards or maximum cost limits for VERs forecasts are
necessary to prevent unjust, unreasonable, or unduly discriminatory
rates.
---------------------------------------------------------------------------
\313\ E.g., AWEA; California PUC; Iberdrola; NaturEner.
---------------------------------------------------------------------------
301. Other commenters argue that the Commission should ensure that
the risks associated with inaccurate schedules or resource specific
forecasts remain with the VER.\314\ Montana PSC states that the
forecasting requirement should be the responsibility of VER instead of
the public utility transmission provider. NorthWestern states that it
is inappropriate to make
[[Page 41530]]
the public utility transmission provider responsible for forecasting
the VER power output when it is the responsibility of the VER to
provide its schedule. NorthWestern points out that, if the public
utility transmission provider provides a forecast of the VER power
production, as proposed by the Proposed Rule, and the VER submits a
different schedule, Control Performance Standard 2 violations may occur
that would not have occurred if an accurate power production forecast
had been submitted by the VER. NorthWestern argues that the forecasting
requirement would place the balancing authority in an unacceptable
position if the forecast or power production data is inaccurate.
Midwest ISO Transmission Owners state that regardless of whether the
public utility transmission provider requires VERs to provide
meteorological data or employs other tools in order to increase the
effectiveness of scheduling and dispatching activities, all generation
resources must retain the ultimate responsibility for determining their
unit's deliverability; accordingly, variations from scheduled
deliveries must remain the responsibility of the generating resource,
including VERs.
---------------------------------------------------------------------------
\314\ E.g., AEP; Large Public Power Council; Midwest ISO
Transmission Owners; Montana PSC; NorthWestern.
---------------------------------------------------------------------------
302. Bonneville Power argues that, if the Commission requires
centralized power production forecasts for public utility transmission
providers with significant amounts of VERs on their systems that intend
to differentiate their Schedule 10 pricing, it is preferable that the
Commission also require all VERs to schedule according to the
centralized forecast component for each plant. Puget explains that, if
the public utility transmission provider's forecast sets the schedule,
then there could be a perverse incentive for public utility
transmission providers to generate inaccurate forecasts and collect
larger generator imbalance charges under Schedule 9; however, if the
VER is permitted to set its own schedule that differs from the public
utility transmission provider's forecast, it remains unclear how the
public utility transmission provider is supposed to manage and deploy
its resources--according to its own forecast or to the VER's schedule.
Puget requests that these questions be clarified before the Commission
implements a power production forecasting requirement for public
utility transmission providers, whether as a stand-alone mandate or as
a precondition to Schedule 10 cost recovery.
303. Invenergy argues that the Final Rule should hold public
utility transmission providers: (1) Accountable for the accuracy of the
forecasts that they use to determine regulation capacity requirements;
and (2) to performance levels that current technology supports.
Invenergy states that ISOs and RTOs that have implemented centralized
wind forecasting are generally realizing accuracy rates of 89 percent
or greater. Invenergy argues that the Final Rule should require the
public utility transmission provider to provide customers with
forecasting performance metrics on a periodic basis and, if forecasts
do not prove to be reliable, require the public utility transmission
provider to take immediate steps (including improving its forecasting
systems and equipment or relinquishing responsibilities to an
independent third party) to ensure that future forecasts are accurate.
304. Commenters state that in RTO regions, the RTO would be the
more appropriate entity to conduct power production forecasting.
National Grid asks the Commission to clarify who the ``transmission
providers'' are that will undertake the energy forecasting
responsibility. National Grid states that the role of developing and
implementing energy forecasting tools is well suited to a centralized
entity with existing capabilities in data collection, region wide
system forecasting and centralized dispatch responsibilities such as
RTOs and ISOs. National Grid requests that the Commission clarify that
for the purposes of its data forecasting Final Rule the term
``transmission provider'' means the ISOs or RTOs in those regions, as
this avoids confusion where the term ``transmission provider'' can
refer to either the ISO or its members.
305. Some commenters point out that many regions are currently
undertaking their own forecasting and data gathering initiatives or
programs to integrate VERs, and request that the Commission allow for
regional flexibility.\315\ Pacific Gas & Electric requests that
individual public utility transmission providers be given flexibility
on how to implement that requirement. Pacific Gas & Electric requests
that in its Final Rule the Commission provide latitude for the
California ISO and other similarly situated transmission providers to
continue their existing programs to gather the relevant meteorological
and operational data, and to propose incremental refinements to them,
so long as the programs maintained by these transmission providers can
accomplish the purposes set forth in the Proposed Rule for gathering
this information.
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\315\ E.g., Massachusetts DPU; Pacific Gas & Electric; Midwest
ISO.
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iv. One Year Data Requirement
306. Some commenters contend that the proposal to require public
utility transmission providers to collect power production forecasting
data for one year prior to instituting a differentiated regulation
requirement for VERs violates cost causation principles and imposes
costs of balancing reserve capacity needed for VERs on other
customers.\316\ Such commenters maintain that the one-year data
collection requirement unreasonably delays public utility transmission
providers from demonstrating that they are entitled to recover
different volumetric amounts associated with providing generator
regulation service from different types of generators.\317\ Bonneville
Power argues that there may be sound economic and operational bases for
providing or procuring differential quantities of incremental and
decremental balancing reserve capacity. Western Farmers suggest that
the Commission allow public utility transmission providers to propose
the volumetric component of the Schedule 10 charge along with the
proposed rates in their initial Schedule 10 compliance filing. Natural
Gas and Puget similarly argue that public utility transmission
providers should have an opportunity to allocate ancillary service
costs as soon as they are justifiably able to do so. MidAmerican
contends that the one-year data collection requirement is inconsistent
with the Westar precedent.
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\316\ E.g., Bonneville Power; Puget; MidAmerican; Southern
California Edison; Natural Gas.
\317\ E.g., EEI; MidAmerican; Puget; WUTC.
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307. Some commenters suggest that public utility transmission
providers should be permitted to establish rates using historical data,
subject to adjustment as necessary over time.\318\ For example,
Bonneville Power states that rates can be updated as public utility
transmission providers gain experience with reductions in the need for
balancing reserve capacity requirements associated with intra-hourly
scheduling, centralized forecasting and any other initiatives.
Similarly, Puget suggests that reductions in the VERs volumetric
component could be incorporated into a subsequent rate filing after
implementation of 15-minute scheduling and power production forecasting
by the utility. NorthWestern suggests that, just as the Commission
routinely allows a proposed rate to take effect on an interim basis
subject to refund until final approval is received, the Commission
likewise should consider
[[Page 41531]]
applying a similar principle in allowing interim regulating service
cost recovery. Pacific Gas & Electric proposes that until one year's
worth of data are available, public utility transmission providers
should be able to use simulated data to estimate the relative
contribution of load, imports, VERs and other generation for the
overall need for generator regulation reserves.
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\318\ E.g., Bonneville Power; Southern California Edison;
California PUC; EEI; NorthWestern.
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308. In contrast, Vestas argues that public utility transmission
providers should be required to implement the two operational changes
immediately and then collect data over at least the next 12 months
regarding the levels of schedule deviations on their systems for all
types of generation. According to Vestas, the Commission should require
the submission of that data to the Commission and take comments from
interested market participants on the appropriate rate mechanism to
permit the recovery of any costs incurred to address remaining
variations between generator schedules and generator output.
309. Organization of Midwest ISO States asks the Commission to
require public utility transmission providers with significant VER
capacity, such as three percent or more of total capacity, to submit
statistical data on the variability of generation across the different
types of generation resources and load. If there is a significant
difference between types of resources, Organization of Midwest ISO
States contends that the public utility transmission provider should be
required to allocate the costs of increased regulation and other
ancillary services developed in the future to the generation resources
causing those costs.
v. Other
310. Some commenters express concern about the static nature of the
rates and volumes in Schedule 10.\319\ SEIA argues that public utility
transmission providers who have selected a methodology and begun to
apply different Schedule 10 rates for different categories of customers
should be required to revisit their forecasting methodologies and rates
on a regular basis. RenewElec notes that data collected over a one-year
period that may feature anomalies (e.g., wind droughts). RenewElec
suggests that the Commission require transmission providers to retain
data provided under the new pro forma LGIA Article 8.4 for at least 10
years and commit to performing annual follow-up studies over a period
of not less than five years that update power production forecasts with
new data received. RenewElec suggests that the Commission include a
biannual re-opener provision for VER-specific Schedule 10 charges, or
through other review and implementation combinations.
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\319\ E.g., SEIA, RenewElec, NaturEner.
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311. NaturEner asserts that an annual re-evaluation of the
integration charge needs to be undertaken to take into account the
impact of increased diversity, improved operations, market innovations
and other changed circumstances, as well as to correct any inaccuracy
in the original (or immediately prior) assessment. NaturEner also
requests clarification regarding whether a VER transmission customer
could be required to pay a VER integration charge in arrears if a
public utility transmission provider is subsequently permitted to levy
the charge.
312. Some commenters oppose the Commission's proposal to group
resources together for the purpose of allocating Schedule 10
volumes.\320\ For example, BrightSource states that assigning all VERs
the same regulation requirement could distort the incentives created by
the cost allocation if they are evaluated as a single, undifferentiated
class. First Wind asserts that the rate should be designed to recognize
the actual variability of output of the resource paying the rate
because two wind generation projects of the same installed capacity and
energy production might have different levels of variability due to
factors such as local differences in the variability of the ``wind
resource'' (the relative wind generating value of the location); the
number, size, and manufacturer of the wind turbines; and differences in
distances between wind turbines. RenewElec offers that high capacity
wind generation units have a disproportionally smaller impact on
variability than lower capacity units. According to AWEA, the
variability of resources within a category cancels each other out to
the benefit of those resources in that category, imposing a
disadvantage on customers that are grouped in smaller categories.
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\320\ E.g., BrightSource; FirstWind; RenewElec; AWEA.
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313. Snohomish County PUD questions whether it is appropriate to
apportion any volume of generator regulation reserves to behind-the-
meter generation. Snohomish County PUD contends that variations in
output from the behind-the-meter generator are, from the perspective of
the public utility transmission provider, indistinguishable from
variations in the distribution utility's load. Accordingly, Snohomish
County PUD asks the Commission to clarify that behind-the-meter
generators--those that are interconnected directly to and consumed by
the load of the local distribution utility rather than a transmission
utility--will not be required to purchase generator balancing capacity
from the public utility transmission provider in the absence of a
voluntary agreement between the public utility transmission provider
and the generator to install appropriate metering that measures the
variability of the generator and to pay the Schedule 10 charges
justified by that variation.
314. Several commenters suggest that the Commission convene a
technical conference or require other processes to determine the
appropriate per-unit and volumetric rates under the proposed Schedule
10.\321\ AWEA states that a technical conference would be appropriate
to establish consistent principles for determining the methodology that
should be used for calculating and allocating Schedule 10 costs. Some
commenters request that the Commission require stakeholder involvement
in connection with the development of Schedule 10 volumes.\322\ For
example, First Wind requests that the Commission require RTOs to
conduct a robust and transparent stakeholder process which attempts to
reach consensus prior to them making an allocation filing, and that
non-RTO public utility transmission providers conduct public workshops
prior to any allocation filing.
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\321\ E.g., AWEA; BrightSource; EPSA; SEIA.
\322\ E.g., California PUC; First Wind; SEIA.
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b. Commission Determination
315. For the reasons discussed above, the Commission is not
implementing a generic Schedule 10 to the pro forma OATT for generator
regulation service. Instead, the Commission takes this opportunity to
respond to the individual commenter concerns regarding the proper
design of a generator regulation service charge in order to provide
guidance in the development of proposals for such services.
316. In response to the Large Public Power Council and Puget, those
public utility transmission providers that choose to propose a rate
schedule for generator regulation service may include opportunity costs
for generator regulation service in certain circumstances. Such
resources are often dispatched in the middle of their operating range
to allow the generator to provide regulation-up as well as
[[Page 41532]]
regulation-down and as a result forego other opportunities. Not to
allow compensation would create a barrier to the provision of services
by frustrating the recovery of legitimate costs.
317. A number of commenters question the appropriate design of the
volumetric component of Schedule 10 rates, i.e., the component in the
Proposed Rule that allowed public utility transmission providers to
require different transmission customers (or generator classes) to
purchase or otherwise account for different quantities of regulation
reserves based on cost causation principles. The Commission agrees that
calculating the relative impact of individual customers or customer
classes on a public utility transmission provider's overall generation
regulating reserve needs and allocating those costs accordingly can be
a difficult and complex determination. However, the Commission believes
that the complexity of these proceedings can be mitigated where
entities take note of, and incorporate, the following principles.
318. First, public utility transmission providers seeking to
distinguish customers into classes for the purpose of requiring them to
purchase or otherwise account for different quantities of generation
regulating reserves should do so only to the extent such classes and
distinctions among classes are reasonably related to operational
similarities and differences among those resources.\323\
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\323\ See Westar, 137 FERC ] 61,142 at PP 27-28.
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319. Second, to the extent a public utility transmission provider
proposes to break customers into specific groups based on operational
characteristics, we expect public utility transmission providers to
provide detailed explanations as to why such classifications are
appropriate if and when they propose to allocate different generating
regulation reserve obligations to different customer classes. The
Commission has required that overall generator regulation requirements
be established by taking diversity benefits into account. Diversity
benefits result from aggregating the variations of all resources so
that one resource's negative deviation can offset some or all of
another resource's positive deviation. When the transactions of two
customers result in diversity benefits, it is incorrect to say that one
customer is benefitting the other but not vice versa. Instead, the
diversity benefits result from both transactions and sharing of these
benefits among the customers is reasonable. In Westar, the Commission
found that this portfolio-wide approach to assessing generator
regulation charges appropriately shares diversity benefits among
generators and load.\324\ Ultimately, this concept will need to be
reconciled with any customer classifications proposed by the public
utility transmission provider in a way that prevents any over-recovery
of these capacity costs.
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\324\ See Westar, 130 FERC ] 61,215 at PP 37-38.
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320. Third, to the extent a public utility transmission provider
proposes to differentiate among customers (or customer classes) in
determining their relative regulating reserve responsibilities, the
public utility transmission provider must demonstrate that the overall
quantity of regulating reserve it requires of its transmission
customers accounts for diversity benefits among all resources and
loads, and the allocations to individual customers (or customer
classes) of their proportionate share is based on the operational
characteristics of such customers (or customer classes).
321. Fourth, weather events such as droughts may affect the
required quantity of generator regulating reserves that the public
utility transmission provider must have in reserve more or less during
one portion of the year versus another portion of the year. In such
cases, these diversity events, though perhaps characterized as
anomalies, should be included in the data set so that the quantity and
costs of such reserves are more reflective of actual system operations.
322. Fifth, there is a relationship between the use of intra-hour
scheduling by transmission customers and the quantity of reserves
needed to provide Schedule 9 generator imbalance service. In other
sections of this Final Rule, the Commission requires all public utility
transmission providers to offer transmission customers the option of
using more frequent transmission scheduling intervals within each
operating hour, at 15-minute intervals, noting that over time public
utility transmission providers will be able to rely more on planned
scheduling and dispatch procedures and less on reserves to maintain
overall system balance. In the Proposed Rule, the Commission sought
comment on whether to condition the ability of public utility
transmission providers to require different transmission customers to
purchase or otherwise account for different quantities of generator
regulating reserves on the implementation of intra-hour scheduling
reforms. Given that such reforms are mandated in this Final Rule, the
Commission concludes that condition to be satisfied.\325\ In designing
any proposals for generator regulation service charges, a public
utility transmission provider should consider the extent to which
transmission customers are using intra-hour scheduling in evaluating
whether to require different transmission customers to purchase or
otherwise account for different quantities of generator regulating
reserves.
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\325\ See supra IV.A.1 (Intra-Hour Scheduling Requirement).
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323. Sixth, there also is a relationship between the use of power
production forecasting and the allocation of generator regulation
reserve quantities to a particular class of customers. The record in
this proceeding demonstrates that the quantity of reserves used to
provide generator regulation service can be most efficiently managed
with the implementation of power production forecasting (as well as
intra-hour scheduling) by public utility transmission providers. While
commenters disagree on the extent to which power production forecasting
may affect reserve commitments, the Commission finds that power
production forecasts can provide public utility transmission providers
with advanced knowledge of system conditions needed to manage the
variability of VER generation through the unit commitment and dispatch
process, rather than through the deployment of reserve services, such
as regulation reserve. Without the increased situational awareness of
projected variability provided by power production forecasts, the
public utility transmission provider's ability to commit or de-commit
resources providing regulation reserves efficiently can be constrained.
This lack of situational awareness potentially can result in rates for
generator regulation service that are unjust and unreasonable or unduly
discriminatory.
324. We recognize that conditioning the allocation of different
quantities of regulation reserves to different transmission customers
on the public utility transmission provider developing and deploying
power production forecasting is contentious. On one hand certain public
utility transmission providers believe that they should either be able
to use historical data or make other approximations to establish the
quantity of regulation reserves to be required of a given transmission
customer or class of customers. On the other hand, transmission
customers that are VERs contend that the Commission has not gone far
enough and that additional reforms are necessary to
[[Page 41533]]
ensure that VERs do not disproportionately bear the burden of the cost
of regulating reserves. The Commission believes that public utility
transmission providers need an effective opportunity to file for cost
recovery, while VERs need assurance that they are not unduly assigned
costs.
325. Accordingly, while the Commission reserves judgment as to the
appropriate power production forecasting requirements for a particular
public utility transmission provider, we expect that the implementation
of power production forecasting will be addressed in any proposal to
require different transmission customers to purchase or otherwise
account for different quantities of generator regulating reserves. For
example, a public utility transmission provider could demonstrate that
it is utilizing power production forecasts (or other comparable
technique) to manage system operating costs and/or to improve
reliability by enabling the more efficient commitment and dispatch of
resources. The Commission agrees with the California PUC that, as part
of such a demonstration, the public utility transmission provider
should explain how the data required from VERs are incorporated into
the power production forecast and how the resulting forecast is used to
support the management of operating costs and/or reserves or otherwise
ensure that capacity costs incurred to provide Schedule 9 service are
prudently incurred.
326. The Commission declines to require the additional forecasting-
related showings suggested by NaturEner and others. The technologies
and techniques for power production forecasting are still being refined
and may differ from region to region. While the recommendations made by
AWEA, Iberdrola, and NaturEner may be appropriate benchmarks for power
production forecasts utilizing today's technology, the Commission
believes that pre-defining these additional criteria would not provide
the flexibility needed for public utility transmission providers to
adopt new forecasting techniques or technologies as they are developed.
The Commission also declines to adopt the further recommendations of
the California PUC and others to include monitoring and reporting
requirements for public utility transmission providers that engage in
power production forecasting. The Commission finds adopting these
requirements to be unnecessary at this time.
327. However, the Commission agrees with Iberdrola and others that
the public utility transmission provider should make the results of any
centralized forecast used by the public utility transmission provider
available through a secure information exchange to VER generators
providing related data. The Commission believes that the VERs should be
able to access the results of the public utility transmission
provider's forecast in order to ensure that the forecasting service is
producing accurate results. Thus, public utility transmission providers
proposing to require different transmission customers to purchase or
otherwise account for different quantities of generator regulating
reserves should explain in their proposals how forecasting results will
be shared.
328. In response to comments regarding forecasting risk, the
Commission clarifies that the transmission customer is responsible for
the accuracy of transmission schedules and the public utility
transmission provider is responsible for the reliability of its system.
Therefore, the public utility transmission provider would utilize the
power production forecast to identify the necessary amount of reserves
and to use those reserves to maintain reliability of the transmission
system. The obligation of the transmission customer is to submit
schedules for deliveries. Power production forecasting is intended to
inform the transmission provider regarding aggregate system variability
that results from having VERs on its system, not to replace
transmission schedules from transmission customers delivering from
VERs. Public utility transmission providers using power production
forecasts should do so to manage uncertainty in the same manner they
use other forecasts of uncertainty for the transmission system. For
example, despite service agreements to serve load, public utility
transmission providers develop and use load forecasts to assure load
can be met reliably and efficiently. Similarly, despite transmission
schedules to deliver from a VER, public utility transmission providers
should use power production forecasts to assure energy can be provided
to load in a reliable and efficient manner.
329. Therefore, the Commission agrees with NorthWestern and others
that the transmission customer maintains responsibility for the
accuracy of its transmission schedule. However, we disagree with
NorthWestern's interpretation concerning NERC Control Performance
Standard 2 violations. A public utility transmission provider is not
responsible for submitting a transmission schedule on behalf of a VER.
As explained above, power production forecasting would be utilized to
identify and acquire the appropriate amount of reserves needed to
integrate VERs reliably. Nothing in this Final Rule alleviates the
public utility transmission provider's obligations under NERC
Reliability Standards.
330. The Commission declines to require transmission customers
delivering from a VER to submit transmission schedules according to the
public utility transmission provider's forecast, as suggested by
Bonneville Power. While the public utility transmission provider is
able to forecast the aggregate variability of the system with greater
accuracy through centralized power production forecasting, the
individual VER may be better able to produce the most accurate schedule
for its particular facility. Requiring a transmission customer to
submit transmission schedules for VER deliveries according to a
centralized forecast would cloud the delineation between the
obligations of the VER and the obligations of the public utility
transmission provider with respect to the provision of transmission
service.
331. The Commission disagrees with Puget's example, and clarifies
that the public utility transmission provider's obligation should be to
deploy its resources according to its own forecast in order to maintain
the reliability of the system. The public utility transmission provider
retains the risk and responsibility for inaccurate procurement of
reserve requirements while the transmission customer retains the
financial risk and responsibility for inaccurate schedules. The
Commission finds that the incentive to avoid Schedule 9 generator
imbalance penalties and any relevant charges for generator regulation
service provides sufficient incentive for VERs to submit an accurate
schedule.
332. The Commission agrees with National Grid and others that, as
the entity providing transmission service under an OATT, the ISO or RTO
would engage in power production forecasting within its region. In
response to Pacific Gas & Electric and others requesting flexibility to
implement power production forecasting, the Commission finds that the
guidance provided affords sufficient flexibility to allow public
utility transmission providers to tailor their forecasting programs to
meet their needs, whether for the purpose of developing proposals for
generator regulation charges or otherwise.
333. The Commission emphasizes that the foregoing discussion is
intended to provide a framework to assist public utility transmission
providers in
[[Page 41534]]
developing proposals for generator regulation service should they
desire to do so. The Commission does not intend this guidance to
preclude a public utility transmission provider from making an
alternative proposal under section 205 of the FPA. However, it does
provide guidance to public utility transmission providers regarding the
facts and circumstances that the Commission may find relevant in
evaluating such proposals.
334. A number of commenters challenged the Commission's proposal to
condition proposals that require different transmission customers to
purchase or otherwise account for different quantities of generator
regulating reserves on performance of the activities discussed above.
These arguments have largely been rendered moot by the Commission's
decision not to adopt the Proposed Rule in that regard. Even as applied
to the guidance provided above, the Commission disagrees that a future
decision by the Commission to condition proposals that require
different transmission customers to purchase or otherwise account for
different quantities of generator regulating reserves on the
performance of certain actions would violate cost causation principles
or otherwise would preclude public utility transmission providers from
recovering prudently incurred costs. In reviewing any future proposal
to allocate a greater quantity of capacity costs to a particular set of
transmission customers, it would be reasonable for the Commission to
consider whether the public utility transmission provider has taken
steps to mitigate such costs. This does not mean, as some commenters
imply, that the public utility transmission provider has no other means
to recover its costs. The public utility transmission provider could
continue to rely on existing rate mechanisms to recover reserve costs
or may propose to require a uniform quantity of generation regulating
reserves from all transmission customers that is commensurate with
transmission customers' proportionate effect on net system variability
and taking diversity benefits into account.
335. The Commission agrees with commenters that implementing other
reforms, such as consolidating balancing authority areas or
implementing an ancillary services market, may be beneficial to the
reliable and efficient integration of VERs. However, the Commission is
not persuaded that these additional reforms are a necessary
precondition to proposals that require different transmission customers
to purchase or otherwise account for different quantities of generator
regulating reserves. As noted in the Proposed Rule, many of these
additional reforms are being discussed in other forums. The Commission
will continue to monitor these proposals as they develop and modify our
approach to this issue as appropriate as conditions develop.
3. Use of Contingency Reserves
a. Commission Proposal
336. In the Proposed Rule, the Commission sought comments from NERC
and industry stakeholders on the steps needed to resolve confusion
regarding the use of contingency reserves to manage extreme ramp events
of VERs.\326\ The Commission also sought comments from NERC and
industry stakeholders on the extent to which some additional type of
contingency reserve service (beyond the services provided under
Schedule 5 and 6 of the pro forma OATT) would ensure that VERs are
integrated into the interstate transmission system in a non-
discriminatory manner while remaining consistent with NERC Reliability
Standards.\327\
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\326\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 100
(citing Schedule 5 (Operating Reserve--Spinning Reserve Service) and
Schedule 6 (Operating Reserve--Supplemental Reserve Service) respond
to contingency events. Spinning Reserve Service is used to serve
load ``immediately in the event of a system contingency'' whereas
Supplemental Reserve Service ``is not available immediately to serve
load but rather within a short period of time.'').
\327\ Id. P 100.
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b. Comments
337. NERC indicates that large wind ramping events are similar to
conventional generator contingency events in that they are large and
relatively infrequent, yet they differ in that wind ramps are much
slower than instantaneous contingency events and may be possible to
forecast. NERC states that the use of contingency reserves to address
wind ramps is similar to what is used to address large, relatively
infrequent wind ramps because contingency reserves are seldom deployed,
yet long ramp durations can make it difficult to include wind ramps as
actual contingencies. NERC explains that Resource and Demand Balancing
(BAL) Reliability Standard BAL-002 (Disturbance Control Performance)
requires ACE to be restored 15 minutes following the disturbance (R4)
and the contingency reserves to be restored within 105 minutes (90
minutes after the 15 minute disturbance recovery period--R6). NERC
states that both of these requirements can be problematic for wind
ramps because they can be longer than the disturbance recovery period
as well as the reserve restoration period.
338. Still, NERC indicates that it may be appropriate to use
contingency reserves in response to a portion of a wind ramp. NERC
states that shared contingency reserves could be used to initiate the
response, allowing time for alternate supply (or load reduction) to be
implemented. NERC suggests that the industry consider developing rules
governing reserve deployment and restoration, similar to those that
currently address conventional contingencies.
339. Other commenters express openness to using contingency
reserves for wind events.\328\ Commenters indicate that there are
discussions in the Northwest Power Pool (NWPP) about the use of
contingency reserves for wind events.\329\ AWEA contends that
contingency reserves should be used for the initial period of an
extreme wind ramp because both contingency events and extreme wind ramp
events are very infrequent, and therefore, the use of contingency
reserves for extreme wind ramp events would be highly unlikely to
coincide with a need to use those reserves for a conventional
generator's contingency event. NextEra urges the Commission to convene
a technical conference to address how to deploy contingency reserves to
address ramp events in a manner that will promote reliability.
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\328\ E.g., Powerex; NaturEner; California PUC; MidAmerican.
\329\ E.g., Powerex; Tacoma Power.
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340. Xcel indicates that there is confusion regarding the use of
contingency reserves to manage extreme ramping events. Xcel states that
the confusion arises as entities attempt to define the allowable
triggering events for the activation of contingency reserves. Xcel
recommends that the standard for contingency reserve activation include
disturbances related to less-than-anticipated VER (e.g., wind)
production, sudden drop-off of VER production, or associated ramp
limitations on balancing resources due to forecast errors. Xcel
contends that ramp events related to VERs are not necessarily caused by
the sudden failure of generation, but instead may be due to an
incorrect wind forecast or limited dispatchable generation response.
For these reasons, Xcel recommends: (1) Expanding the definition of
disturbances to include ramp events which may occur over a half-hour
time frame; (2) including a measurement technique related to a ramp
event in BAL-002; (3) identifying a specific
[[Page 41535]]
restoration period in BAL-002 (e.g., 45 minutes) related to contingency
reserves that were deployed for ramping events; and (4) identifying
compliance metrics and other issues related to deployment of
contingency reserves for ramp-limited events. Xcel recommends that the
Commission request that NERC begin a standards drafting process to
consider revisions to the existing BAL-002 standard to address the
issues discussed by Xcel.
341. Other commenters express reservations with using contingency
reserves in response to wind events is an improper use of contingency
reserves.\330\ Duke indicates to the extent that there is a need for a
new service to address VER ramp rates, a new rate schedule should be
developed for such a service. Pacific Gas & Electric states that there
may be a need for new integration services to incorporate VERs into the
reliable operation of the grid. Pacific Gas & Electric submits that
various industry activities are already underway to consider these
issues, and the Final Rule should endorse their continued efforts.
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\330\ E.g., Tacoma Power; ENBALA; Grant PUD; California ISO;
Duke; Pacific Gas & Electric.
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c. Commission Determination
342. Based on comments received, the Commission concludes that the
issues related to the appropriate use of contingency reserves under
NERC Reliability Standards need further study and vetting before any
action is considered. Indeed, comments range from expressing confusion
over what would constitute an extreme VER event to asking the
Commission to define ``ramp'' with some specificity. Rather than
opining on any of the comments and risk providing guidance without the
benefit of more information, the Commission finds that the better
course of action is to allow industry to continue its work and direct
our staff to monitor those efforts and engage industry as appropriate.
V. Other Issues
1. Regulatory Text
a. Commission Proposal
343. As part of the Proposed Rule, the Commission sought comment on
a minor revision to 18 CFR 35.28. To date, when amending its
regulations concerning the open access requirements of the pro forma
OATT, the Commission has listed by name Commission rulemaking
proceedings promulgating and amending the pro forma OATT when
explaining the details of a public utility transmission provider's
obligation to have an OATT on file with the Commission. The Commission
proposed to no longer explicitly reference, by name, prior Commission
rulemaking proceedings promulgating and amending the pro forma OATT in
its regulations. Likewise, the Proposed Rule included a similar change
with respect to a public utility transmission provider's obligation to
have standard generator interconnection procedures and agreements and
standard small generator interconnection procedures and agreements on
file with the Commission.\331\
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\331\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 12 &
n.29.
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b. Comments
344. No comments were received on this aspect of the Proposed Rule.
c. Commission Determination
345. The Commission adopts its proposed minor revision to 18 CFR
35.28. We find that the existing process for amending regulations
concerning the pro forma OATT, which necessitates listing by name
Commission rulemaking proceedings promulgating and amending the pro
forma OATT when explaining the details of a public utility transmission
provider's obligation to have an OATT on file with the Commission, is
increasingly cumbersome and provides little, if any, benefit. Thus, the
Commission will no longer explicitly reference, by name, prior
Commission rulemaking proceedings promulgating and amending the pro
forma OATT in its regulations. Likewise, the Final Rule adopts a
similar change with respect to a public utility transmission provider's
obligation to have standard generator interconnection procedures and
agreements and standard small generator interconnection procedures and
agreements on file with the Commission.
2. Market Mechanisms
a. Comments
346. Several commenters ask the Commission to revise specific RTO
and ISO market rules not at issue in the Proposed Rule, while other
commenters seek to have the Commission address additional market
mechanisms for the non-RTO and ISO areas. For example, Environmental
Defense Fund states that the Proposed Rule does not reform the day-
ahead market to increase VER participation and decrease the amount of
costly out-of-market commitments, leading to unjust and unreasonable
rates, and undue discrimination against VERs. In addition, ACSF asserts
that scheduling in the day-ahead market and in the unit commitment
process should be reformed. ACSF states that the technology that makes
15-minute schedules feasible in the spot market also makes reforms
possible in these other areas. According to ACSF, it is important to
prevent the least clean and efficient generation from dominating
dispatch at all hours, especially in the unit commitment process.
347. Environmental Defense Fund further states that because VERs
are only permitted to bid a portion of their capacity into the market,
they generally receive a lower price. According to Environmental
Defense Fund, many capacity markets require bidders to also participate
in the day-ahead market, which most VERs do not do because of the
financial risk associated with failing to meet day-ahead obligations.
Thus, Environmental Defense Fund argues that the Commission must
consider the available options to facilitate VER participation in
capacity markets.
348. With regard to non-RTO regions, EPSA states that the Proposed
Rule does not sufficiently address the lack of market mechanisms
available in non-RTO regions to conventional generation resources,
which have the ability to contribute to VERs integration. EPSA suggests
that possible market mechanisms and other competitive options for
integrating VERs in the non-RTO regions should be considered as part of
the technical conference that EPSA has requested. Similarly,
Independent Power Producers Coalition--West states that without an
organized ISO or RTO market, public utilities must face regulatory
pressure to advance their integration of VERs and sharing of data,
otherwise the utilities have little incentive to move toward better
integration between transmission providers and balancing authorities.
Independent Power Producers Coalition--West contends that the lack of a
competitive ancillary services market that would allow independent
power producers the opportunity to provide generator imbalance services
in WECC results in unjust and unreasonable rates.
349. Tres Amigas contends that Order Nos. 888 and 890 have left
little room for a market to develop balancing services outside of an
ISO/RTO, because the primary provider of these services, the balancing
authority, has to acquire the capability to provide the ancillary
services on behalf of all its transmission customers and then sell the
services at cost-based rates. Tres Amigas states that the Commission
should have a two-fold objective: (1) Determining how market
[[Page 41536]]
forces can identify and competitively price the resources that will be
used by balancing authorities for balancing; and (2) establishing
appropriate mechanisms for allocating the costs incurred by balancing
authorities to acquire these resources in the marketplace. Further,
Tres Amigas asserts that the Commission should grant market-based rates
to new entrants in order to promote formation of a vibrant market for
balancing services that includes participation by new technologies.
Tres Amigas states that the balancing authorities should then file
proposals to allocate the costs incurred to balance the system among
load and generation (including generation within the control area that
is scheduled to another control area). According to Tres Amigas, these
cost allocation proposals should take into account the extent to which
different market participants contribute to the costs of acquiring
balancing services and benefit from such services.
350. Recycled Energy urges the Commission to consider implementing
various payments designed to compensate efficient gas generators and
combined heat and power facilities for the flexibility they provide to
utilities. In addition, Recycled Energy asserts that the Commission
could improve the grid's reliability and efficiency by encouraging the
placement of distributed generators in ways that reduce line losses and
obtain ancillary benefits. Similarly, Business Council asserts that the
OATT should be revised to ensure that flexible resources (such as
natural gas and pumped storage facilities) are better able to provide
their services to system operators who integrate VERs, and that these
services are properly valued. Business Council explains that flexible
generation resources should be given more opportunities to sell their
balancing services to transmission providers and should be paid a just
and reasonable rate for these services. Business Council argues that if
the Commission adopts a universal requirement for 15-minute scheduling,
it should make clear that generators should be able to supply balancing
services on the same 15-minute (or less) basis.
b. Commission Determination
351. The pro forma OATT terms and conditions of service create the
platform by which the public utility transmission provider makes
available non-discriminatory open, access transmission service. Since
the issuance of Order No. 888, the Commission has taken numerous
actions to ensure that the principles enunciated in that rule continue
to remain true, allowing all types of resources--existing and new--
access to the grid for the benefit of developing competitive markets.
In response to commenters like Independent Power Producers-West, EPSA
and Tres Amigas who assert that the Commission should take various
steps to establish a competitive ancillary services market or other
market mechanisms, we believe that the reforms in this Final Rule
continue to facilitate the development of competitive markets without
imposing any particular type of structure for doing so. The Commission
allows third party sellers to make sales of ancillary services at
market-based rates, requires all public utility transmission providers
to offer open access transmission service and undertake open and
transparent transmission planning, and allows transmission customers to
self-supply their own ancillary services. The Commission has long-
standing precedent on cost allocation and has long supported reserve
sharing and power pooling arrangements. Nothing in this rule is
intended to prevent or create a barrier to the further development of
competitive markets. Indeed, we think that the reforms adopted herein
should help to facilitate the further development of competitive
markets by allowing transmission customers to tailor their transmission
schedules and, in turn, better manage generator imbalance and ancillary
services costs. As the liquidity of intra-hour energy products
stabilizes, market participants also may begin to commit or otherwise
acquire fewer reserves in advance, with the knowledge that they can
purchase additional reserves on an as-needed basis from third parties.
Requiring public utility transmission providers to offer intra-hour
scheduling is a necessary predicate to facilitate these market
opportunities.
352. For similar reasons we decline the request from Recycled
Energy and Business Council to expand the scope of this rulemaking
proceeding to include additional payments to flexible generation. Both
commenters urge the Commission to adopt mechanisms that would increase
payments to flexible generation resources, such as high-efficiency
natural gas facilities, so as to properly value the flexibility they
provide to transmission providers. The Commission has already
addressed, in the context of the organized markets, compensation for
resources providing frequency regulation and is currently exploring a
similar issue in bilateral markets outside of RTOs and ISOs.\332\ In
this proceeding, the Commission is primarily concerned with providing
reforms that will provide public utility transmission providers with
greater awareness of the variability experienced on their systems, as
well as providing transmission customers with a tool to manage
imbalances from schedules by providing for 15-minute adjustments to
schedules. How these public utility transmission providers choose to
provide this service is beyond the scope of this inquiry.
---------------------------------------------------------------------------
\332\ See Frequency Regulation Compensation in the Organized
Wholesale Power Markets, Order No. 755, 76 FR 67260 (Oct. 31, 2011),
FERC Stats. & Regs. ] 31,324 (2011); Third-Party Provision of
Ancillary Services; Accounting and Financial Reporting for New
Electric Storage Technologies, 139 FERC ] 61,245 (NOPR).
---------------------------------------------------------------------------
353. With regard to commenters that request additional changes to
the RTO and ISO day-ahead and capacity markets to facilitate VER
integration, we fail to see the direct connection between the specific
reforms of the Commission's Proposed Rule and the reforms requested.
Commenters did not establish that connection and failed to demonstrate
that the Commission's proposed reforms are unjust and unreasonable
without the additional requested reforms. Instead, these commenters
merely asked that the Commission extend the scope of the rule. As such,
we find that commenters' requests that we require additional reforms to
RTO/ISO day-ahead, residual unit commitment, and capacity market rules
are beyond the scope of this proceeding.
354. Finally, we cannot allow sales of energy or capacity at
unchecked rates, even by new entrants, as suggested by Tres
Amigas.\333\ As noted above, the Commission allows for sales at market-
based rates upon a showing of lack of market power and is in the
process of considering ways to streamline the market-based rate showing
for certain ancillary services.\334\
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\333\ See Market-Based Rates For Wholesale Sales Of Electric
Energy, Capacity And Ancillary Services By Public Utilities, Order
No. 697, 72 FR 39904 (July 20, 2007), FERC Stats. & Regs. ] 61,295,
at P 320 (2007).
\334\ See Third-Party Provision of Ancillary Services;
Accounting and Financial Reporting for New Electric Storage
Technologies, 139 FERC ] 61,245 (NOPR).
---------------------------------------------------------------------------
c. Pipeline Transportation Nomination Procedures
i. Comments
355. Some commenters assert that if the Commission requires
transmission providers to allow intra-hour transmission scheduling to
accommodate VERs, the Commission must also consider the impact of such
requirements on the operation of natural-gas-fired electric generation
[[Page 41537]]
units, and the concomitant need to modify pipeline transportation
service nomination procedures to calibrate gas transportation and usage
more closely with the operation of natural gas-fired electric
generation units to support VERs.\335\ Specifically, APPA contends that
despite access to real-time electronic metering and flow control and
technological advances that enable the electronic submission of gas
nominations, the current time period used to process pipeline
transportation service nominations and to schedule natural gas is the
same time period (up to 4 hours) that was adopted over a decade and a
half ago. APPA notes that this already substantial disconnect between
the nomination and scheduling procedures used in the natural gas and
electric power industries will only become more severe if intra-hour
scheduling is adopted. Similarly, Joint Parties request that the
Commission open a companion docket to examine barriers that may exist
in the natural gas industry that inhibit the timely access to natural
gas that is needed to ensure the seamless integration of VERs.\336\
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\335\ E.g., Joint Parties; TVA; Midwest Energy; APPA.
\336\ TVA contends that the Commission should reevaluate its
policy of not allowing a firm gas transportation holder to take
precedence over (i.e., bump) a non-firm customer, because gas-fired
generators paying for firm gas transportation service must be able
to support electric needs in general and in integrating VERs
specifically.
---------------------------------------------------------------------------
356. American Gas and INGAA state that gas transmission systems
have developed innovative services to accommodate the needs of gas-
fired generators to access gas supplies quickly in response to electric
system dispatch orders. American Gas and INGAA explain that these
offerings demonstrate that individual, tailored solutions may better
address gas-electric coordination concerns than a modification of the
gas nomination schedule. For this reason, American Gas encourages the
Commission to continue to be open to creative market solutions to meet
the needs of gas-fired generators in ways that do not unnecessarily
affect existing shippers in adverse ways. American Gas also encourages
the Commission to hold a technical conference or other non-NAESB forum
to discuss ways in which the natural gas and electric industries can
work together.
357. American Gas further contends that the Commission's
consideration of gas-electric coordination issues should not focus
narrowly on the gas nomination and scheduling cycle as a primary
solution to the reliability issues which both industries face. While
American Gas believes that a single, nationwide gas nomination schedule
is essential to the efficient functioning of the natural gas system, a
modification to that schedule alone is not the most effective means to
address gas-electric coordination issues.
358. AEP adds that while the proposed scheduling option appears on
the surface to be feasible within the power industry, the increased
quantity of VERs and subsequent increased ramping capability
requirements will further exacerbate the operational difficulties
associated with the varied scheduling timelines existing between the
gas and power industries. AEP concludes that such discrepancies place
the gas-fired generation operators, whose typically superior ramping
capabilities will become increasingly beneficial, in a position of
speculating on fuel supply needs because they are unsure whether the
increase in variable generation will mean an increased need for the
faster ramping capabilities of gas.
359. AEP notes that these differences have existed for many years,
and managing them has become more challenging with the introduction of
RTO-administered markets, as unit commitment is generally made by the
RTO, and not the individual asset owner. AEP argues that any proposed
scheduling practices related to incremental VER penetration must
account for such inter-market dependencies.
360. Spectra Entities notes that the interface issues between the
gas and electric industries go beyond revisiting coordinating and the
gas/electric scheduling timelines. Spectra Entities argues that there
are regulatory policy and market barriers discouraging the electric
industry in some markets from contracting for adequate firm gas supply
and firm transportation arrangements to serve those generators which
must run in order to maintain the reliability of the electric grid. For
example, the Commission's ``no-bump'' policy and the need to coordinate
scheduling of interruptible services are irrelevant during peak or high
load days in natural gas markets, because interruptible capacity is
rarely available on the pipeline grid under those conditions. Spectra
Entities argue that unless these barrier issues are addressed, any
changes to coordination and scheduling or the offering of innovative
transportation solutions will not be sufficient to achieve the
Commission's goals.
ii. Commission Determination
361. While comments asking the Commission to undertake reforms to
natural gas pipeline rules and procedures in order to facilitate
greater cross-market coordination are beyond the scope of this
proceeding, we agree that the interdependence of these two industries
merits careful attention. The Commission has recently addressed
proposed changes to the gas pipeline nomination procedures. In the
past, the Commission has urged the industry, working through NAESB, to
consider changes to its nomination procedures to provide better
coordination between gas and electric scheduling.\337\ More recently,
in Order No. 587-U, the Commission acknowledged that NAESB lacked
consensus to implement any such changes and did not find a nationwide
scheduling solution in response to concerns over gas pipeline
nomination procedures (including the ``no-bump'' rule).\338\ While
eschewing nationwide changes, Order No. 587-U emphasized that
``individual pipelines may be able to offer special services or
increased nomination opportunities that better fit the profile of gas-
fired generation.'') \339\ In fact, some pipelines have begun to offer
special services to facilitate the flexibility needs of gas-fired
generation.\340\
---------------------------------------------------------------------------
\337\ See Standards for Business Practices for Interstate
Natural Gas Pipelines: Standards for Business Practices for Public
Utilities, Order No. 698, FERC Stats, & Regs ] 31,251, at P 69
(2007).
\338\ Order No. 587-U, FERC Stats. & Regs. ] 31,307 at P 27.
\339\ Id.
\340\ See Texas Gas Transmission LLC, 138 FERC ] 61,176 (2012).
---------------------------------------------------------------------------
362. On March 30, 2012, a number of entities submitted further
comments on gas-electric coordination issues in response to a notice
issued in Docket No. AD12-12-000 that requested comments in response to
a set of questions and other text concerning gas-electric
interdependence issued by Commissioner Moeller on February 3, 2012. The
Commission is currently evaluating these comments to determine what, if
any, additional steps would be appropriate to take to facilitate
coordination between the gas and electric industries.
3. Power Factor Design
a. Comments
363. Midwest ISO Transmission Owners state that Order No. 661
exempted wind generators from having to maintain power factor design
criteria absent a specific finding in the relevant system impact study
that the generator needs to maintain a specific power factor in order
to ensure safety and reliability. Midwest ISO Transmission Owners
submit that the Commission should convene a technical conference to
examine this issue, or allow
[[Page 41538]]
individual transmission providers to file to eliminate this exemption
from their pro forma LGIAs or generator interconnection agreements.
Midwest ISO Transmission Owners explain that wind and other VERs have
obtained significant penetration levels in many areas of the country,
such that wind is no longer a new technology that needs protection.
Midwest ISO Transmission Owners contend that eliminating this exemption
will ensure that wind does not receive an unfair competitive basis.
b. Commission Determination
364. Since issuance of the Proposed Rule in this proceeding, the
Commission has directed staff to convene a technical conference in
Docket No. AD12-10-000 to examine whether the Commission should
reconsider or modify the reactive power provisions of Order No. 661-A
and examine what evidence could be developed under Order No. 661 to
support a request to apply reactive power requirements more broadly
than to individual wind generators during the interconnection study
process.\341\ The Commission concludes that potential issues regarding
the exemption provided under Order No. 661-A are better addressed in
that proceeding.
---------------------------------------------------------------------------
\341\ Reactive Power Resources, Notice of Technical Conference,
Docket No. AD12-10-000 (issued Feb. 17, 2012).
---------------------------------------------------------------------------
VI. Compliance
A. Commission Proposal
365. In the Proposed Rule, the Commission indicated that each
public utility transmission provider must submit a compliance filing
within six months of the effective date of the Final Rule revising its
OATT and LGIA to demonstrate compliance with the Final Rule. The
Commission indicated that to demonstrate compliance, a public utility
transmission provider must file: (1) Revisions to its OATT to implement
15-minute scheduling; (2) revisions to its LGIA to include a
requirement for interconnection customers whose generating facility is
a VER to provide data to the public utility transmission provider when
the public utility transmission provider is developing and deploying
power production forecasting for VERs; and (3) the addition of Schedule
10 to the OATT, which includes the same per unit rate from their
currently effective Schedule 3, and a blank or unfilled volumetric
component, among other things.
366. The Commission acknowledged that public utility transmission
providers may have provisions in their existing OATTs and LGIAs that
the Commission has deemed to be consistent with or superior to the pro
forma OATT and LGIA. The Commission indicated that where these
provisions are being modified by the Final Rule, public utility
transmission providers must either comply with the Final Rule or
demonstrate that these previously-approved variations continue to be
consistent with or superior to the pro forma OATT and LGIA as modified
by the Final Rule.
367. The Commission also proposed that transmission providers that
are not public utilities would have to adopt the requirements of the
Final Rule as a condition of maintaining the status of their safe
harbor tariff or otherwise satisfying the reciprocity requirement of
Order No. 888.\342\
---------------------------------------------------------------------------
\342\ Order No. 888, FERC Stats. & Regs. at 31,760-763.
---------------------------------------------------------------------------
B. Comments
368. Commenters addressing the six month timeframe generally argue
that the proposed compliance deadline does not provide enough time for
the industry to implement intra-hour scheduling effectively.\343\
Specifically, commenters assert that additional time is needed to allow
transmission providers time to: (1) Develop necessary revisions to
inter-regional agreements and procedures, and finish ongoing pilot
programs; and (2) evaluate all potential impacts to operations and
address issues regarding reliability via NERC, and perhaps business
standards via NAESB.
---------------------------------------------------------------------------
\343\ E.g., MidAmerican; EEI; FriiPwr; NRECA; Southern
California Edison; Pacific Gas & Electric; Grant PUD; NextEra; PNW
Parties; Powerex; NV Energy; New York ISO; ISO/RTO Council.
---------------------------------------------------------------------------
369. Southern California Edison argues that regional differences
and the need to implement intra-hour scheduling efficiently require
careful consideration of each region's scheduling rules. Specifically,
Southern California Edison suggests that the Commission provide three
years to implement 30-minute scheduling followed by an 18-24 month
evaluation period before deciding if 15-minute intra-hour scheduling is
necessary. Pacific Gas & Electric recommends that the Commission
lengthen the implementation timeline for intra-hour scheduling, so that
regional technical conferences on intra-hour scheduling can be convened
for affected transmission providers, and so that ongoing pilot studies
on intra-hour scheduling may be completed.
370. NorthWestern comments that six months is insufficient time for
a compliance filing implementing the intra-hour scheduling requirements
of the Proposed Rule. NorthWestern argues that compliance will include,
but not be limited to, implementation of software and hardware
upgrades, adoption of common regional scheduling practices in the
region with jurisdictional and non-jurisdictional balancing
authorities, and hiring and properly training of additional staff.
NorthWestern encourages the Commission to be flexible and allow
balancing authorities the ability to define implementation timeframes,
perhaps up to one year before the compliance filing is due.
371. Commenters also point more generally to areas of the Proposed
Rule that may require additional time for compliance. Midwest ISO
Transmission Owners state, for example, that additional time may be
needed to make changes that are highly technical or require an
extensive stakeholder process to implement.\344\ Midwest ISO suggests
that at least 18 months should be allotted for transmission providers
to submit compliance filings revising their OATT, LGIA, or other
documents.\345\ MidAmerican recommends that sufficient time be
allocated so that transmission providers may (1) evaluate and address
all potential impacts to operations and reliability and (2) be afforded
the necessary time to procure resources, develop and adopt
administrative processes, conduct training, and perform testing and
validation critical to successfully effectuate the proposed reforms.
---------------------------------------------------------------------------
\344\ Midwest ISO Transmission Owners at 16.
\345\ Midwest ISO at 15.
---------------------------------------------------------------------------
372. EEI suggests that the Commission not require the changes set
forth in the Proposed Rule until the regional planning and cost
allocation Final Rules have gone through any rehearing and legal
challenges that may develop. On the other hand, Iberdrola supports the
Commission's proposal to require a compliance filing within six months;
however, if the Commission extends the deadline, Iberdrola recommends
that implementation of Schedule 10 occur coincidentally with the
implementation of the other two proposed operational changes.
C. Commission Determination
373. The Commission extends the deadline for compliance filings by
6 months so that public utility transmission providers will have 12
months from the effective date of this Final Rule to submit their
compliance filings. The Commission also provides the pro forma tariff
language that public utility transmission providers must include in
their OATTs and LGIAs, with modifications to the language based
[[Page 41539]]
upon the comments received, as discussed within the body of this Final
Rule.\346\
---------------------------------------------------------------------------
\346\ See Appendix A and B for the adopted pro forma OATT and
LGIA provisions consistent with this Final Rule.
---------------------------------------------------------------------------
374. Consistent with the discussion in the intra-hourly scheduling
section, the Commission requires public utility transmission providers
to revise their OATTs to provide an opportunity for transmission
customers to submit transmission schedules at 15-minute intervals
within 12 months of the effective date of this Final Rule.\347\ Public
utility transmission providers with provisions in their existing OATTs
that the Commission has deemed to be consistent with or superior to the
pro forma OATT being modified by the Final Rule can seek to demonstrate
in their compliance filings that those previously-approved variations
continue to be consistent with or superior to the pro forma OATT as
modified by the Final Rule. In addition, public utility transmission
providers may submit alternative proposals that are consistent with or
superior to the intra-hour scheduling requirements of this Final Rule
and are otherwise just and reasonable and not unduly discriminatory or
preferential.\348\
---------------------------------------------------------------------------
\347\ See Appendix A for the revised section 13.8 and 14.6 of
the pro forma OATT provisions consistent with this Final Rule. As
noted supra Sec. IV.A.1 (Intra-Hour Scheduling Requirement), the
implementation of 15-minute scheduling will only apply to intertie
transactions in organized wholesale energy markets.
\348\ See supra Sec. IV.A.1 (Intra-Hour Scheduling
Requirement).
---------------------------------------------------------------------------
375. Consistent with the discussion in the data reporting section,
the Final Rule modifies the compliance obligation set forth in the
Proposed Rule and requires public utility transmission providers to
modify their pro forma LGIAs to effectuate the data reporting
requirement within 12 months of the effective date of this Final Rule
rather than the six months initially proposed.\349\ The Commission
adopts proposed Article 8.4 of the pro forma LGIA, as modified per the
discussion in the data reporting section. The Commission also adopts
the proposed definition of VER. The Commission appreciates that public
utility transmission providers in some regions, including RTOs and
ISOs, have already implemented meteorological or forced outage
reporting under relevant tariffs, business practices and/or markets
rules. Such public utility transmission providers may seek to
demonstrate in their compliance filings how continued use of these
existing tariffs, business practices and/or market rules is adequate to
satisfy the requirements of this Final Rule using the independent
entity variation standard set forth in Order No. 2003, if relevant, or
by demonstrating variations from the pro forma OATT are consistent with
or superior to the requirements of this Final Rule.\350\
---------------------------------------------------------------------------
\349\ See Appendix B for the revisions to the pro forma LGIA
consistent with this Final Rule. Specifically, a new Article 8.4 and
a new definition in Article 1 have been added to the pro forma LGIA
and conforming revisions have been made to the table of contents.
\350\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
---------------------------------------------------------------------------
376. The Commission concludes that 12 months is a reasonable amount
of time to implement the requirements of this Final Rule. Many public
utility transmission providers have already implemented some form of
sub-hourly scheduling, resolving many of the issues that must be
addressed in order to accept transmission schedules on a 15-minute
interval. Twelve months also is an adequate amount of time for public
utility transmission providers to determine the extent to which
meteorological and forced outage data are necessary to support power
production forecasting. Although we are extending the compliance
deadline to 12 months from the compliance schedule in the Proposed
Rule, we do not believe that more than 12 months will be necessary.
Therefore, we will not extend the compliance deadline beyond 12 months,
nor will we adopt commenters' other proposed recommendations.
377. Finally, the Commission also adopts the proposal that
transmission providers that are not public utilities must adopt the
requirements of the Final Rule as a condition of maintaining the status
of their safe harbor tariff or otherwise satisfying the reciprocity
requirement of Order No. 888.\351\
---------------------------------------------------------------------------
\351\ Order No. 888, FERC Stats. & Regs. at 31,760-63.
---------------------------------------------------------------------------
VII. Information Collection Statement
378. The Office of Management and Budget (OMB) regulations require
approval of certain information collection and data retention
requirements imposed by agency rules.\352\ Upon approval of a
collection(s) of information, OMB will assign an OMB control number and
an expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to these collections
of information unless the collections of information display a valid
OMB control number.
---------------------------------------------------------------------------
\352\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------
379. The Commission is submitting the proposed modifications to its
information collections to OMB for review and approval in accordance
with section 3507(d) of the Paperwork Reduction Act of 1995.\353\ In
the Proposed Rule, the Commission solicited comments on the need for
this information, whether the information will have practical utility,
the accuracy of provided burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected or retained,
and any suggested methods for minimizing the respondent's burden,
including the use of automated information techniques. The Commission
also included a table that listed the estimated public reporting
burdens for the proposed reporting requirements, as well as a
projection of the costs of compliance for the reporting requirements.
---------------------------------------------------------------------------
\353\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------
380. The Commission did not receive any comments specifically
addressing the burden estimates provided in the Proposed Rule. However,
commenters did respond to questions in the NOPR regarding the specific
hardware, software, and personnel changes that are necessary to
implement intra-hour scheduling. As noted in Section IV above, some
parties argue that the cost to implement intra-hour scheduling will be
modest, while other commenters state that implementation costs may be
significant. In addition to the Commission's responses to the comments
previously provided, the Commission believes that the revised burden
estimates below are representative of the average burden on
respondents.
381. In the Final Rule, the Commission adds two burden categories
that were not included in the Proposed Rule burden estimates. First,
the Commission includes a burden estimate for transmission providers
who choose to share power production forecast results with VERs.
Second, the Commission includes a burden estimate for transmission
providers who choose to voluntarily share VER-provided meteorological
and forced outage data with third parties. Neither of these additional
categories is required under the Final Rule. However, the Commission
assumes that all Transmission Providers will implement these changes
for the purposes of calculating a burden estimate. The Commission also
notes that certain VERs will have increased burden due to submission of
intra-hour schedules to transmission providers. However, the Commission
assumes that only VERs who choose to participate in intra-hour
scheduling are those who will receive at
[[Page 41540]]
least as much benefit as the cost that must be expended. For this
reason, the Commission is not including a burden estimate for this
category in the table below.
Burden Estimate and Information Collection Costs: The estimated
Public Reporting burden and cost for the requirements contained in this
Final Rule follow.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of
Data collection FERC 516 (as contained Number and type of responses per Hours per response Total annual hours
in Final Rule in RM10-11) respondents respondent
(1)...................... (2) (3)...................... (1 x 2 x 3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Conforming tariff changes to require 142 Transmission 1 8 first year only........ 1,136 first year only.
intra-hourly scheduling, waiver, or Providers.\354\
deviation request; and rate treatment
terms for Ancillary Service.
Implementation of intra-hourly 142 Transmission 1 30 reoccurring........... 4,260 reoccurring.
scheduling. Providers.
Conforming changes to LGIA.\355\ 142 Transmission 1 20 first year only....... 2,840 first year only.
Providers.
Sharing of power production 142 Transmission 1 30 reoccurring........... 4,260 reoccurring.
forecasting results with VER. Providers.
Sharing of VER provided meteorological 142 Transmission 1 30 reoccurring........... 4,260 reoccurring.
and forced outage data with third Providers.
party entities (e.g. NOAA, balancing
authority area).
Provision of meteorological and forced 160 Interconnection 1 60 reoccurring........... 9,600 reoccurring.
outage data to public utility Customers with VERs per
transmission providers for use in year.\357\
power production forecasting.\356\
-----------------------------------------------------------------------------------------------------------------
Totals............................ ......................... .............. ......................... 26,356 first year + reoccurring.\358\
-------------------------------------------
22,380 subsequent years.\359\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost to Comply: The Commission has projected the total cost of
compliance to be $3,004,584 in the first year, and $2,551,330 each year
after.
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\354\ The Commission estimated in the NOPR that 134 transmission
providers would have additional burdens due to the Proposed Rule.
Since then, the Commission has identified eight additional
transmission providers who are non-public utilities that file
reciprocity open access transmission tariffs that are also expected
to voluntarily comply with this rule.
\355\ Consistent with the approach taken in Order No. 2003,
public utility transmission providers with power production
forecasting systems in place via tariff provisions and/or other
mechanisms will be required to demonstrate that deviations from the
pro forma LGIA are consistent with or superior to the pro forma
LGIA.
\356\ Once a data exchange is implemented, the Commission
expects that this process will be automated and require little to no
day to day burden.
\357\ The Commission estimates that there will be approximately
160 VERs that will sign an LGIA each year during the period from
July 2012-July 2015 potentially subject to this requirement. This
update from the NOPR represents more recent data.
\358\ First year hours total 26,356, the sum of first year and
reoccurring hours.
\359\ Annual hours total 22,380, the sum of all reoccurring
hours.
---------------------------------------------------------------------------
Total Annual Hours in the first year (26,356 hours) @ $114 an hour
[average cost of attorney ($200 per hour), consultant ($150), technical
($80), and administrative support ($25)] = $3,004,584.
Total Annual Hours in subsequent years (22,380 hours) @ $114 an
hour = $2,551,320.
Title: FERC-516, Electric Rate Schedules and Tariff Filings
Action: Proposed Collection.
OMB Control No. 1902-0096.
Respondents for this Rulemaking: Transmission Providers (an RTO or
ISO also may file some materials on behalf of its members) and Variable
Energy Resources.
Frequency of Information: As indicated in the table.
Necessity of Information: The Federal Energy Regulatory Commission
is adopting these amendments to the pro forma OATT to remedy
operational challenges related to the increased integration of VERs to
the bulk electric system. The purpose of this Final Rule is to
strengthen the pro forma OATT, so VERs can be reliably and efficiently
integrated into the electric grid and to ensure that Commission-
jurisdictional services are provided at rates, terms and conditions
that are just and reasonable and not unduly discriminatory or
preferential. This Final Rule seeks to achieve this goal by amending
the pro forma OATT and LGIA to incorporate provisions that require
intra-hourly transmission scheduling and require interconnection
customers whose generating facilities are VERs to provide
meteorological and operational data to public utility transmission
providers for the purpose of power production forecasting. The
Commission also provides guidance regarding the development of
proposals for generator regulation service.
Internal Review: The Commission has reviewed the proposed changes
and has determined that the changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has assured itself, by means of internal review, that there
is specific, objective support for the burden estimates associated with
the information collection requirements.
382. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director], email:
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
Comments concerning the collection of information and the associated
burden estimate(s), may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission, phone: (202) 395-4638, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically
to the following email address:
[[Page 41541]]
oira_submission@omb.eop.gov. Comments submitted to OMB should include
OMB Control No. 1902-0096 and Docket No. RM10-11-000.
VIII. Environmental Analysis
383. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\360\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Rule under Sec.
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\361\
---------------------------------------------------------------------------
\360\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regs. Preambles 1986-1990 ] 30,783 (1987).
\361\ 18 CFR 380.4(a)(15) (2010).
---------------------------------------------------------------------------
IX. Regulatory Flexibility Act Analysis
384. The Regulatory Flexibility Act of 1980 (RFA) \362\ generally
requires a description and analysis of Final Rules that will have a
significant economic impact on a substantial number of small entities.
This Final Rule applies to public utilities that own, control or
operate interstate transmission facilities \363\ and to variable energy
resources. The total estimated number of small public utility
transmission providers \364\ impacted by this Final Rule is estimated
to be ten. The Commission assumes that the Final Rule will impact all
the applicable small transmission providers equally at an average cost
of $13,500 per year. The Commission does not consider this to be a
significant economic impact. In any event, each of these entities may
seek waiver of these requirements.\365\ The Commission estimates that
all of the applicable VERs (160 per year) are small. Of these 160
entities, approximately 100 that are greater than 20 MW will be
required to comply with the Final Rule and approximately 60 that are 20
MW or less will have the option to comply with the rule. The Commission
estimates that each VER will have an average cost of $6,800 per year
because of the Final Rule. The Commission does not consider this to be
a significant economic impact on these small entities. The costs
incurred by VERs due to this rule are offset by an expected reduction
in energy imbalance penalties that will be assessed to VERs in the
future due to improved forecasting and reduced uncertainty across 15-
minute scheduling periods compared to hour-long scheduling periods.
Accordingly, the Commission certifies that this Final Rule will not
have a significant economic impact on a substantial number of small
entities.
---------------------------------------------------------------------------
\362\ 5 U.S.C. 601-612 (2006).
\363\ Other than those that have received waiver of the
obligation to comply with Order Nos. 888, 889, and 890.
\364\ A ``small entity'' as referenced in the RFA refers to the
definition provided in section 3 of the Small Business Act where a
firm is ``small'' if, including its affiliates, it is primarily
engaged in the generation, transmission, and/or distribution of
electric energy for sale and its total electric output for the
preceding fiscal year did not exceed 4 million megawatt hours.
\365\ The criteria for waiver that would be applied under this
rulemaking for small entities is unchanged from that used to
evaluate requests for waiver under Order Nos. 888, 889, and 890.
---------------------------------------------------------------------------
X. Document Availability
385. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5:00
p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC
20426.
386. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
387. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or email at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
XI. Effective Date and Congressional Notification
388. These regulations are effective September 11, 2012. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of OMB, that this rule
is not a ``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996. The Commission will submit
this Final Rule to both houses of Congress and the Government
Accountability Office.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission. Commissioner LaFleur is dissenting in part with a
separate statement attached.
Commissioner Clark voting present.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the Commission amends Part 35,
Chapter I, Title 18, Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
0
1. The authority citation for Part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 71-7352.
0
2. Amend Sec. 35.28 as follows:
0
a. Paragraphs (c)(1) introductory text and (c)(1)(i) through
(c)(1)(iii) are revised.
0
b. Paragraphs (c)(1)(v) and (c)(1)(vi) are revised.
0
c. Paragraphs (c)(3) introductory text and (c)(3)(ii) are revised.
0
d. Paragraph (c)(4) is revised.
0
e. Paragraph (d) is revised.
0
f. Paragraphs (e)(1) introductory text, (e)(1)(ii), and (e)(2) are
revised.
0
g. Paragraphs (f)(1) introductory text and (f)(1)(i) are revised.
0
h. Paragraphs (f)(1)(ii) through (f)(1)(iv) are removed and reserved.
0
i. Paragraph (f)(3) is revised.
0
j. Paragraph (f)(4) is removed.
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(c) Non-discriminatory open access transmission tariffs.
(1) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce must have on file with the Commission an open access
transmission tariff of general applicability for transmission services,
including ancillary services, over such facilities. Such tariff must be
the pro forma tariff promulgated by the Commission, as amended from
time to time, or such other tariff as may be approved by the Commission
consistent with the principles set forth in Commission rulemaking
proceedings promulgating and amending the pro forma tariff.
[[Page 41542]]
(i) Subject to the exceptions in paragraphs (c)(1)(ii),
(c)(1)(iii), (c)(1)(iv), and (c)(1)(v) of this section, the open access
transmission tariff, which tariff must be the pro forma tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff, and accompanying rates must be filed no later than 60
days prior to the date on which a public utility would engage in a sale
of electric energy at wholesale in interstate commerce or in the
transmission of electric energy in interstate commerce.
(ii) If a public utility owns, controls, or operates facilities
used for the transmission of electric energy in interstate commerce, it
must file the revisions to its open access transmission tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff, pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in accordance with the procedures
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
(iii) If a public utility owns, controls, or operates transmission
facilities used for the transmission of electric energy in interstate
commerce, such facilities are jointly owned with a non-public utility,
and the joint ownership contract prohibits transmission service over
the facilities to third parties, the public utility with respect to
access over the public utility's share of the jointly owned facilities
must file the revisions to its open access transmission tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in accordance with the procedures
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
* * * * *
(v) If a public utility obtains a waiver of the tariff requirement
pursuant to paragraph (d) of this section, it does not need to file the
open access transmission tariff required by this section.
(vi) Any public utility that seeks a deviation from the pro forma
tariff promulgated by the Commission, as amended from time to time,
must demonstrate that the deviation is consistent with the principles
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
* * * * *
(3) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce, and that is a member of a power pool, public utility holding
company, or other multi-lateral trading arrangement or agreement that
contains transmission rates, terms or conditions, must have on file a
joint pool-wide or system-wide open access transmission tariff, which
tariff must be the pro forma tariff promulgated by the Commission, as
amended from time to time, or such other open access transmission
tariff as may be approved by the Commission consistent with the
principles set forth in Commission rulemaking proceedings promulgating
and amending the pro forma tariff.
* * * * *
(ii) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed on or before May 14,
2007, a public utility member of such power pool, public utility
holding company or other multi-lateral arrangement or agreement that
owns, controls, or operates facilities used for the transmission of
electric energy in interstate commerce must file the revisions to its
joint pool-wide or system-wide open access transmission tariff required
by Commission rulemaking proceedings promulgating and amending the pro
forma tariff pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA in accordance with the procedures
set forth in Commission rulemaking proceedings promulgating and
amending the pro forma tariff.
* * * * *
(4) Consistent with paragraph (c)(1) of this section, every
Commission-approved ISO or RTO must have on file with the Commission an
open access transmission tariff of general applicability for
transmission services, including ancillary services, over such
facilities. Such tariff must be the pro forma tariff promulgated by the
Commission, as amended from time to time, or such other tariff as may
be approved by the Commission consistent with the principles set forth
in Commission rulemaking proceedings promulgating and amending the pro
forma tariff.
(i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to its open access
transmission tariff required by Commission rulemaking proceedings
promulgating and amending the pro forma tariff pursuant to section 206
of the FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Commission rulemaking
proceedings promulgating and amending the pro forma tariff.
(ii) If a Commission-approved ISO or RTO can demonstrate that its
existing open access transmission tariff is consistent with or superior
to the pro forma tariff promulgated by the Commission, as amended from
time to time, the Commission-approved ISO or RTO may instead set forth
such demonstration in its filing pursuant to section 206 in accordance
with the procedures set forth in Commission rulemaking proceedings
promulgating and amending the pro forma tariff.
(d) Waivers. A public utility subject to the requirements of this
section and Order No. 889, FERC Stats. & Regs. ] 31,037 (Final Rule on
Open Access Same-Time Information System and Standards of Conduct) may
file a request for waiver of all or part of the requirements of this
section, or Part 37 (Open Access Same-Time Information System and
Standards of Conduct for Public Utilities), for good cause shown.
Except as provided in paragraph (f) of this section, an application for
waiver must be filed no later than 60 days prior to the time the public
utility would have to comply with the requirement.
(e) Non-public utility procedures for tariff reciprocity
compliance.
(1) A non-public utility may submit an open access transmission
tariff and a request for declaratory order that its voluntary
transmission tariff meets the requirements of Commission rulemaking
proceedings promulgating and amending the pro forma tariff.
* * * * *
(ii) If the submittal is found to be an acceptable open access
transmission tariff, an applicant in a Federal Power Act (FPA) section
211 or 211A proceeding against the non-public utility shall have the
burden of proof to show why service under the open access transmission
tariff is not sufficient and why a section 211 or 211A order should be
granted.
(2) A non-public utility may file a request for waiver of all or
part of the reciprocity conditions contained in a public utility open
access transmission tariff, for good cause shown. An application for
waiver may be filed at any time.
(f) Standard generator interconnection procedures and agreements.
(1) Every public utility that is required to have on file a non-
discriminatory open access transmission tariff under this section must
amend such tariff by adding the standard interconnection procedures and
[[Page 41543]]
agreement and the standard small generator interconnection procedures
and agreement required by Commission rulemaking proceedings
promulgating and amending such interconnection procedures and
agreements, or such other interconnection procedures and agreements as
may be required by Commission rulemaking proceedings promulgating and
amending the standard interconnection procedures and agreement and the
standard small generator interconnection procedures and agreement.
(i) Any public utility that seeks a deviation from the standard
interconnection procedures and agreement or the standard small
generator interconnection procedures and agreement required by
Commission rulemaking proceedings promulgating and amending such
interconnection procedures and agreements, must demonstrate that the
deviation is consistent with the principles set forth in Commission
rulemaking proceedings promulgating and amending such interconnection
procedures and agreements.
* * * * *
(3) A public utility subject to the requirements of this paragraph
(f) may file a request for waiver of all or part of the requirements of
this paragraph (f), for good cause shown.
* * * * *
Note: The following appendices will not be published in the
Code of Federal Regulations.
Appendix A: List of Short Names of Commenters on the Federal Energy
Regulatory Commission's Notice of Proposed Rulemaking on Integration of
Variable Energy Resources--Docket No. RM10-11-000, November 2010
------------------------------------------------------------------------
Short name or acronym Commenter
------------------------------------------------------------------------
A123......................... A123 Systems, Inc.
AEP.......................... American Electric Power Service
Corporation
ALLETE....................... ALLETE Inc.
ACSF......................... American Clean Skies Foundation
Alstom....................... Alstom Grid, Inc.
American Gas................. American Gas Association
APPA......................... American Public Power Association
Argonne National Lab......... Argonne National Laboratory
Arizona Corporation Arizona Corporation Commission
Commission.
Avista....................... Avista Corporation
AWEA......................... American Wind Energy Association
Beacon Power................. Beacon Power Corporation
Bonneville Power............. Bonneville Power Administration
BP Companies................. BP Energy Company and BP Wind Energy
North America, Inc.
BrightSource................. BrightSource Energy, Inc.
Business Council............. Business Council for Sustainable Energy
CESA......................... California Energy Storage Alliance
California State Water California Department of Water Resources
Project. State Water Project
California ISO............... California Independent System Operator
Corporation
California PUC............... California Public Utilities Commission
CEERT........................ Center for Energy Efficiency and
Renewable Technologies
Center for Rural Affairs..... Center for Rural Affairs
CMUA......................... California Municipal Utilities
Association; Cities of Alameda, Anaheim,
Azusa, Banning, Burbank, Cerritos,
Colton, Corona, Glendale, Gridley,
Healdsburg, Hercules, Lodi, Lompoc,
Moreno Valley, Needles, Palo Alto,
Pasadena, Pittsburg, Rancho Cucamonga,
Redding, Riverside, Roseville, Santa
Clara, Shasta Lake, Ukiah, and Vernon;
the Imperial, Merced, Modesto, and
Turlock Irrigation Districts; the
Northern California Power Agency;
Southern California Public Power
Authority; Transmission Agency of
Northern California; Lassen Municipal
Utility District; Power and Water
Resources Pooling Authority; Sacramento
Municipal Utility District; the Trinity
and Truckee Donner Public Utility
Districts; the Metropolitan Water
District of Southern California; and the
City and County of San Francisco, Hetch-
Hetchy
Clean Line................... Clean Line Energy Partners, LLC
CGC.......................... Coalition for Green Capital
Defenders of Wildlife........ Wilderness Society and Defenders of
Wildlife
Detroit Edison............... Detroit Edison Company
Dominion..................... Dominion Resources Services, Inc.
Duke......................... Duke Energy Corporation
EEI.......................... Edison Electric Institute
ELCON........................ Electricity Consumers Resource Council
EPSA......................... Electric Power Supply Association
ENBALA....................... ENBALA Power Networks
Entergy...................... Entergy Services, Inc.
Environmental Defense Fund... Environmental Defense Fund
E.ON C&R..................... E.ON Climate & Renewables North America
Exelon....................... Exelon Corporation
Federal Trade Commission..... Federal Trade Commission
FirstEnergy.................. FirstEnergy Service Company
First Wind................... First Wind Energy, LLC
FriiPwr...................... FriiPwr USA Ltd
Grant PUD.................... Public Utility District No. 2 of Grant
County, Washington
Grays Harbor PUD............. Public Utility District No. 1 of Grays
Harbor County, Washington
Iberdrola.................... Iberdrola Renewables, Inc.
Idaho Power.................. Idaho Power Company
Independent Energy Producers. Independent Energy Producers Association
[[Page 41544]]
Independent Power Producers Arizona Competitive Power Alliance;
Coalition-West. Colorado Independent Energy Association;
Independent Energy Producers Association
(California); New Mexico Independent
Power Producers Coalition; and the
Northwest & Intermountain Power
Producers Coalition.
INGAA........................ Interstate Natural Gas Association of
America
Invenergy Wind............... Invenergy Wind Development LLC
ISO New England.............. ISO New England Inc. and the New England
Power Pool
ISO/RTO Council.............. Alberta Electricity System Operator;
California Independent System Operator;
Electric Reliability Council of Texas;
Independent Electricity System Operator
of Ontario; ISO New England, Inc.;
Midwest Independent Transmission System
Operator, Inc.; New Brunswick System
Operator; New York Independent System
Operator, Inc.; PJM Interconnection,
L.L.C.; and Southwest Power Pool, Inc.
ITC Companies................ ITCTransmission; Michigan Electric
Transmission Company, LLC; ITC Midwest
LLC; and ITC Great Plains, LLC
Joint Parties................ Arizona Public Service Company; The
Boeing Company, El Paso Electric; New
York Independent System Operator; Old
Dominion Electric Cooperative; PJM
Interconnection, L.L.C.; Salt River
Project Agriculture Improvement and
Power District; Southwest Power Pool;
Tennessee Valley Authority; Tucson
Electric Power Company; UNS Gas, Inc.;
and the Vermont Department of Public
Service
Joint Initiative............. Joint Initiative Facilitators
Large Public Power Council... Austin Energy; Chelan County Public
Utility District No. 1; Clark Public
Utilities, Colorado Springs Utilities;
CPS Energy (San Antonio); ElectriCities
of North Carolina; Grant County Public
Utility District; IID Energy (Imperial
Irrigation District); JEA (Jacksonville,
FL); Long Island Power Authority; Los
Angeles Department of Water and Power;
Lower Colorado River Authority; MEAG
Power; Nebraska Public Power District;
New York Power Authority; Omaha Public
Power District; Orlando Utilities
Commission; Platte River Power
Authority; Puerto Rico Electric Power
Authority; Sacramento Municipal Utility
District; Salt River Project; Santee
Cooper; Seattle City Light; Snohomish
County Public Utility District No. 1;
and Tacoma Public Utilities
LADWP........................ Department of Water and Power of the City
of Los Angeles
Massachusetts DPU............ Massachusetts Department of Public
Utilities
MidAmerican.................. MidAmerican Energy Holdings Company
Midwest Energy............... Midwest Energy, Inc.
Midwest ISO.................. Midwest Independent Transmission System
Operator, Inc.
Midwest ISO Transmission Ameren Services Company, as agent for
Owners. Union Electric Company d/b/a Ameren
Missouri; Ameren Illinois Company d/b/a
Ameren Illinois and Ameren Transmission
Company of Illinois; American
Transmission Company LLC; Big Rivers
Electric Corporation; City Water, Light
& Power (Springfield, IL); Dairyland
Power Cooperative; Duke Energy
Corporation for Duke Energy Ohio, Inc.,
Duke Energy Indiana, Inc., and Duke
Energy Kentucky, Inc.; Great River
Energy; Hoosier Energy Rural Electric
Cooperative, Inc. (``Hoosier''); Indiana
Municipal Power Agency; Indianapolis
Power & Light Company (``IPL'');
Michigan Public Power Agency;
MidAmerican Energy Company; Minnesota
Power (and its subsidiary Superior
Water, L&P); Montana-Dakota Utilities
Co.; Northern Indiana Public Service
Company; Northern States Power Company,
a Minnesota corporation, and Northern
States Power Company, a Wisconsin
corporation, subsidiaries of Xcel Energy
Inc. (``Xcel Energy''); NorthWestern
Wisconsin Electric Company; Otter Tail
Power Company; Southern Illinois Power
Cooperative; Southern Indiana Gas &
Electric Company (d/b/a Vectren Energy
Delivery of Indiana); Southern Minnesota
Municipal Power Agency; Wabash Valley
Power Association, Inc.; and Wolverine
Power Supply Cooperative, Inc.
M-S-R Public Power Agency.... Modesto Irrigation District; City of
Santa Clara, California; and City of
Redding, California
Montana PSC.................. Montana Public Service Commission
NEMA......................... National Electrical Manufacturers
Association
National Grid................ National Grid USA
NRECA........................ National Rural Electric Cooperative
Association
Natural Gas.................. Natural Gas Supply Association
NaturEner.................... NaturEner USA, LLC
NE Conference of PUCs........ New England Conference of Public
Utilities Commissioners
NESCOE....................... New England States Committee on
Electricity
NV Energy.................... Nevada Power Company and Sierra Pacific
Power Company
New York ISO................. New York Independent System Operator,
Inc.
NextEra...................... NextEra Energy, Inc.
NERC......................... North American Electric Reliability
Corporation
NAESB........................ North American Energy Standards Board
NOAA......................... National Oceanic and Atmospheric
Administration
NorthWestern................. NorthWestern Corporation
Organization of Midwest ISO Organization of Midwest ISO States
States.
Oregon & New Mexico PUC...... Public Utility Commissioners of Oregon
and New Mexico and Paul Newman, Arizona
Commissioner
Pacific Gas & Electric....... Pacific Gas and Electric Company
PNW Parties.................. Avista Corporation; the Bonneville Power
Administration; Idaho Power Company;
NorthWestern Corporation, dba
NorthWestern Energy; PacifiCorp;
Portland General Electric Company; the
Public Generating Pool (Tacoma Power,
Eugene Water and Electric Board, and
Public Utility Districts for Chelan,
Clark, Cowlitz, Douglas, Grant,
Klickitat, Pend Oreille, and Snohomish
counties); the Public Power Council;
Puget Sound Energy, Inc.; and Seattle
City Light
[[Page 41545]]
PJM.......................... PJM Interconnection, L.L.C.
Powerex...................... Powerex Corporation
Public Interest Organizations Alliance for Clean Energy New York;
Center for Rural Affairs; Citizens
Utility Board of Wisconsin; Climate and
Energy Project; Conservation Law
Foundation; Defenders of Wildlife;
Energy Conservation Council of
Pennsylvania; Energy Future Coalition;
Environment Northeast; Environmental
Defense Fund; Environmental Law & Policy
Center; Fresh Energy; Great Plains
Institute; Natural Resources Defense
Council; Office of the Ohio Consumers'
Counsel; Pace Energy and Climate Center;
Project for Sustainable FERC Energy
Policy; Sierra Club; The Wilderness
Society; Union of Concerned Scientists;
Western Grid Group; Western Resource
Advocates; and Wind on the Wires
Public Power Council......... Public Power Council
Puget........................ Puget Sound Energy, Inc.
Recycled Energy.............. Recycled Energy Development
RENEW........................ Renewable Energy New England, Inc.
RenewElec.................... The RenewElec Project
SMUD......................... Sacramento Municipal Utility District
San Diego Gas & Electric..... San Diego Gas & Electric Company
Snohomish County PUD......... Public Utility District No. 1 of
Snohomish County, Washington
SEIA......................... Solar Energy Industries Association and
the Large-Scale Solar Association
Southern California Edison... Southern California Edison Company
Southern..................... Southern Company Services, Inc.
Southern MN Municipal........ Southern Minnesota Municipal Power Agency
SWEA......................... Southwest Energy Alliance
Southwestern................. Southwestern Power Administration
Spectra Entities............. Spectra Energy Transmission, LLC and
Spectra Energy Partners, LP
Sunflower and Mid-Kansas..... Sunflower Electric Power Corporation and
Mid-Kansas Electric Company, LLC
TA Miller.................... T.A. Miller
Tacoma Power................. City of Tacoma, Department of Public
Utilities, Light Division (Washington)
Tres Amigas.................. Tres Amigas LLC
TVA.......................... Tennessee Valley Authority
US Bureau of Reclamation..... United States Bureau of Reclamation
Utility Economic Engineers... Utility Economic Engineers
Vestas....................... Vestas-American Wind Technology, Inc.
Viridity Energy.............. Viridity Energy, Inc.
Vote Solar................... Vote Solar Initiative
WUTC......................... Washington Utilities and Transportation
Commission
WestConnect.................. Arizona Public Service Company; El Paso
Electric Company, Imperial Irrigation
District; NV Energy, Public Service
Company of Colorado; Public Service
Company of New Mexico; Sacramento
Municipal Utility District; Salt River
Project; Southwest Transmission
Cooperative, Inc.; Transmission Agency
of Northern California; Tri-State
Generation and Transmission Association,
Inc.; Tucson Electric Power Company and
Western Area Power Administration
Western Farmers.............. Western Farmers Electric Cooperative
Western Grid................. Western Grid Group
Xcel......................... Xcel Energy Services Inc.
Xtreme Power................. Xtreme Power Inc.
------------------------------------------------------------------------
Appendix B: Pro Forma Open Access Transmission Tariff
The Commission amends the following sections of the pro forma
OATT:
a. Section 13.8
b. Section 14.6
13.8 Scheduling of Firm Point-To-Point Transmission Service:
Schedules for the Transmission Customer's Firm Point-To-Point
Transmission Service must be submitted to the Transmission Provider
no later than 10:00 a.m. [or a reasonable time that is generally
accepted in the region and is consistently adhered to by the
Transmission Provider] of the day prior to commencement of such
service. Schedules submitted after 10:00 a.m. will be accommodated,
if practicable. Hour-to-hour and intra-hour (four intervals
consisting of fifteen minute schedules) schedules of any capacity
and energy that is to be delivered must be stated in increments of
1,000 kW per hour [or a reasonable increment that is generally
accepted in the region and is consistently adhered to by the
Transmission Provider]. Transmission Customers within the
Transmission Provider's service area with multiple requests for
Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their service requests at a
common point of receipt into units of 1,000 kW per hour for
scheduling and billing purposes. Scheduling changes will be
permitted up to twenty (20) minutes [or a reasonable time that is
generally accepted in the region and is consistently adhered to by
the Transmission Provider] before the start of the next scheduling
interval provided that the Delivering Party and Receiving Party also
agree to the schedule modification. The Transmission Provider will
furnish to the Delivering Party's system operator, hour-to-hour and
intra-hour schedules equal to those furnished by the Receiving Party
(unless reduced for losses) and shall deliver the capacity and
energy provided by such schedules. Should the Transmission Customer,
Delivering Party or Receiving Party revise or terminate any
schedule, such party shall immediately notify the Transmission
Provider, and the Transmission Provider shall have the right to
adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:
Schedules for Non-Firm Point-To-Point Transmission Service must be
submitted to the Transmission Provider no later than 2:00 p.m. [or a
reasonable time that is generally accepted in the region and is
consistently adhered to by the Transmission Provider] of the day
prior to commencement of such service. Schedules submitted after
2:00 p.m. will be accommodated, if practicable. Hour-to-hour and
intra-hour (four intervals consisting of fifteen minute schedules)
schedules of energy that is to be delivered must be stated in
increments of 1,000 kW per hour [or a reasonable increment that is
generally accepted in the region and is consistently adhered to by
the Transmission Provider]. Transmission Customers within
[[Page 41546]]
the Transmission Provider's service area with multiple requests for
Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their schedules at a common Point
of Receipt into units of 1,000 kW per hour. Scheduling changes will
be permitted twenty (20) minutes [or a reasonable time that is
generally accepted in the region and is consistently adhered to by
the Transmission Provider] before the start of the next scheduling
interval, provided that the Delivering Party and Receiving Party
also agree to the schedule modification. The Transmission Provider
will furnish to the Delivering Party's system operator, hour-to-hour
and intra-hour schedules equal to those furnished by the Receiving
Party (unless reduced for losses) and shall deliver the capacity and
energy provided by such schedules. Should the Transmission Customer,
Delivering Party or Receiving Party revise or terminate any
schedule, such party shall immediately notify the Transmission
Provider, and the Transmission Provider shall have the right to
adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
Appendix C: Pro Forma Large Generator Interconnection Agreement
The Commission amends and/or adds the following sections of the
pro forma LGIA:
a. Table of Contents (Add Article 8.4, Provision of Data from a
Variable Energy Resource)
b. Article 1 (Add definition of Variable Energy Resource)
c. Article 8.4
Article 1 Definition
Variable Energy Resource shall mean a device for the production
of electricity that is characterized by an energy source that: (1)
Is renewable; (2) cannot be stored by the facility owner or
operator; and (3) has variability that is beyond the control of the
facility owner or operator.
Article 8.4 Provision of Data From a Variable Energy Resource
The Interconnection Customer whose Generating Facility is a
Variable Energy Resource shall provide meteorological and forced
outage data to the Transmission Provider to the extent necessary for
the Transmission Provider's development and deployment of power
production forecasts for that class of Variable Energy Resources.
The Interconnection Customer with a Variable Energy Resource having
wind as the energy source, at a minimum, will be required to provide
the Transmission Provider with site-specific meteorological data
including: temperature, wind speed, wind direction, and atmospheric
pressure. The Interconnection Customer with a Variable Energy
Resource having solar as the energy source, at a minimum, will be
required to provide the Transmission Provider with site-specific
meteorological data including: temperature, atmospheric pressure,
and irradiance. The Transmission Provider and Interconnection
Customer whose Generating Facility is a Variable Energy Resource
shall mutually agree to any additional meteorological data that are
required for the development and deployment of a power production
forecast. The Interconnection Customer whose Generating Facility is
a Variable Energy Resource also shall submit data to the
Transmission Provider regarding all forced outages to the extent
necessary for the Transmission Provider's development and deployment
of power production forecasts for that class of Variable Energy
Resources. The exact specifications of the meteorological and forced
outage data to be provided by the Interconnection Customer to the
Transmission Provider, including the frequency and timing of data
submittals, shall be made taking into account the size and
configuration of the Variable Energy Resource, its characteristics,
location, and its importance in maintaining generation resource
adequacy and transmission system reliability in its area. All
requirements for meteorological and forced outage data must be
commensurate with the power production forecasting employed by the
Transmission Provider. Such requirements for meteorological and
forced outage data are set forth in Appendix C, Interconnection
Details, of this LGIA, as they may change from time to time.
LaFLEUR, Commissioner, dissenting in part:
I am dissenting in part on this Final Rule.
I strongly support renewable energy, and I have stated many times
that I believe one of the most important jobs of this Commission is to
support the development of rules to address new power supply choices
being made at the state and federal level. For that reason, I support
the requirements in the rule for intra-hour scheduling and power
production forecasting, as well as the guidance we provide on generator
regulation service charges.
I am dissenting on the narrow point of the compliance requirements
in the Final Rule. As noted in the rule, we heard from many parties
about ongoing efforts to establish intra-hour scheduling and other
market improvements in various regions. However, the rule as issued
would only allow parties to demonstrate compliance through incremental
reforms beyond those already underway, without any explanation of why
the ongoing efforts are insufficient. I would give regions more
flexibility to demonstrate on compliance that these ongoing efforts
meet the objectives of the rule.
Accordingly, I respectfully dissent in part.
Cheryl A. LaFleur,
Commissioner.
[FR Doc. 2012-15762 Filed 7-12-12; 8:45 am]
BILLING CODE 6717-01-P